An economically superior material

Material selection plays a vital role for any industry, and there is no exception for the oil and gas sector. In onshore pipelines projects, pipeline material and its welding accounts for the majority of the cost, whilst in natural gas pipelines it is usually 60% of the project allocated budget (CAPEX). Choosing the right pipeline material with optimised grade therefore leads to enormous savings in project capital cost. However, it’s very technically challenging, interesting, and sensitive to select the pipeline material in view of techno commercial aspects; factors such as fluid type, fluid composition, fluid velocity, sour or corrosive, presence of solid particles, pipe size, design conditions, operating parameters, design life, material properties, fabricability, severe environment conditions, material availability, performance and their combination will have a significant influence. While selecting materials, consideration should be given to their safe design and reliable performance under the anticipated in-service conditions over the lifetime of the component.

Process environment

Hydrocarbon fluids are majorly classified as crude oil, natural gas, gas condensate, multiphase, liquid hydrocarbons, produced water, etc. Material deterioration is quite common in its lifecycle due to direct contact between the fluid and internal wall of the pipe in various conditions such as uninterrupted fluid flow, fluid composition, improper periodical maintenance, differential pressure, and velocity. The basic principles to avoid material deterioration are creating a barrier between the internal wall of the pipe to fluid contact, or using better resistant material against the fluid composition and/or injecting corrosion inhibition in the fluid. Higher percentage of CO₂, H₂S, chlorides, sulphur, water cut, organic acids, solid suspended particles and oxygen will cause damage, loss of the material and ultimately reduces the material life.

When CO₂ in the fluid mixes with water it forms carbonic acid, resulting in iron carbide scales at an elevated temperature. The metal begins to corrode and will be enhanced when oxygen and organic acids dissolve the protective iron carbide, preventing further scale formation. Presence of bicarbonates increases the alkalinity of the fluid and reduces the corrosivity. Corrosion resistance alloys (CRAs) are considered immune to this in most conditions, but some of the lower grade stainless steel (SS) type 13Cr may suffer at higher temperatures and low pH. The materials resistance to CO₂ corrosion in the order CS < CS with lining < SS 300 series < 22 Cr < 6Mo < GRP.

The primary concern with hydrogen sulphide (H₂S) is hydrogen attack on the metal which causes it to become brittle. Fluids with high levels of H₂S are termed ‘sour’ and NACE defines the H₂S levels above 0.05 psi of partial pressure as a sour condition for gas phases. In aqueous phases, above 10 ppm mass is considered sour …

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