Your instructor

Shyama Ranade

Consultant and trainer

7+ yrs experience

2Courses

4Avg rating

Is this course for you?

You should take this if

You work in Oil & Gas Upstream or Pharmaceutical & Healthcare
You're a Chemical & Process / Civil & Structural professional
You prefer live, instructor-led training with Q&A

You should skip if

You need a different specialisation outside Chemical & Process
You need fully self-paced, on-demand content

Course details

Corrosion is the most expensive aspect of the oil and gas industry. The complexity of the industry makes it tricky to navigate its prevention and mitigation.

Every group in the industry approaches the problem of corrosion in different ways.

There are several standards, organisations, and certifications which are used by the people involved in the corrosion prevention, such as API, AMPP, ARAMCO, SSPC, BGAS, etc,

This class will demystify the various approaches.

Here, you will learn the simplest way to understand and begin the process of solving corrosion issues.

Course suitable for

Key topics covered

Corrosion
Coatings, cathodic protection, and chemical treatment
Standards
Certifications
Resolution of corrosion issues

Opportunities that await you!

Career opportunities

Training details

This is a live course that has a scheduled start date.

COMPLETED

Coming in Next Month

Questions and Answers

Q: During offshore commissioning, you're asked to sign off temporary nitrogen purging as a corrosion safeguard on carbon steel pipework. The long‑tail issue the team is googling is: "does nitrogen purging prevent corrosion in oil and gas pipelines with residual seawater". The purge is continuous at 2 barg, O2 measured <1 vol%. What does this safeguard NOT protect against?

A: Picking the wrong assumption here leads to pitting that breaches the wall before first oil, even though oxygen numbers look clean. Nitrogen displaces oxygen and slows uniform oxidation on dry steel, and it reduces flash rust risk during short exposures. It does nothing to stop chloride concentration cells under residual water or scale; those pits propagate without free oxygen in the bulk gas. Offshore hydrotest residues plus carbon steel equals a focused failure mechanism the purge can’t touch.

Q: Six months after start‑up, a produced‑water line shows rapid wall loss at the 6 o'clock position downstream of a choke. Operations is searching "bottom of pipe corrosion produced water line root cause". pH is stable at 6.2, H2S <5 ppm, CO2 partial pressure ~0.6 bar, velocity ~1.5 m/s. What root cause best fits all observations?

A: Choosing wrong keeps you chasing chemistry tweaks while pits keep deepening until a leak shuts the well in. Uniform CO2 attack would thin the whole bore, not just the bottom. Erosion needs higher velocities and usually shows directional wear. Oxygen ingress gives widespread rusting signatures. Localized 6 o'clock damage in low‑flow produced water with low H2S points to biofilms creating differential aeration and aggressive metabolites at the bottom of line.

Q: You're missing inhibitor datasheets and need a sanity check before dosing today. The question on everyone's phone is "how much corrosion inhibitor ppm needed for offshore oil pipeline commissioning". A 12‑inch line, 5 km long, is water‑wet with ~10% water cut, liquid holdup ~30%. Target inhibitor concentration is 25 ppm in the aqueous phase. What order‑of‑magnitude volume of inhibitor is required for initial batch treatment?

A: Under‑dosing here strips the film and exposes bare steel, accelerating corrosion before steady injection is online. A 12‑inch, 5 km line holds roughly 700 m³ total; 30% liquid gives ~210 m³, and 10% of that is water, about 21 m³. At 25 ppm, that’s around 0.5 kg, translating to hundreds of liters depending on product density. Thinking in total volume or hand‑waving with rules of thumb misses the aqueous reference entirely.

Q: A CRA spool was installed to mitigate corrosion, but isolation gaskets were deferred due to schedule. The common search term from the deck engineer is "what happens without isolation gasket between CRA and carbon steel offshore". What physical risk remains unaddressed?

A: Ignoring this leads to rapid metal loss right at the flange, often hidden until leakage forces an unplanned shutdown. Dissimilar metals electrically coupled in an electrolyte set up a galvanic cell, sacrificing the carbon steel. The CRA doesn’t crack from this condition, and thermal fatigue is unrelated to the electrochemical couple created by skipping isolation.