L80 13Cr vs Super 13Cr — Tubing Selection Guide

The choice between L80 13Cr and Super 13Cr is one of the most consequential material selection decisions in the completion of CO₂-corrosive gas and gas condensate wells. Specifying L80 13Cr where Super 13Cr is required risks premature corrosion failure and well integrity loss. Over-specifying Super 13Cr where L80 13Cr is adequate adds 40–80% to the tubing string cost with no engineering return. The decision framework is straightforward once the well's corrosion parameters are defined — but it requires accurate reservoir data and careful comparison against the qualified corrosion envelopes of both grades.

ZC Steel Pipe supplies both L80 13Cr and Super 13Cr tubing and casing, with corrosion qualification data and EN 10204 3.2 MTC. This guide covers the engineering basis for choosing between the two grades, the specific parameters that drive the upgrade decision, H2S constraints, cost considerations, and procurement guidance for both grades.

Grade Overview

Both L80 13Cr and Super 13Cr are martensitic stainless steels that derive their CO₂ corrosion resistance from a passive chromium oxide film on the steel surface. The passive film prevents CO₂-saturated brine from reaching the steel substrate, stopping the electrochemical corrosion reactions that would otherwise cause rapid weight loss and pitting in carbon steel.

The difference between the two grades is the stability and robustness of that passive film under increasingly demanding conditions — higher temperature, higher CO₂ partial pressure, and higher chloride concentration all work to break down the passive film and initiate localised corrosion.

Head-to-Head Comparison

The Three Upgrade Triggers

Upgrade from L80 13Cr to Super 13Cr when any of the following conditions apply:

1. Temperature above 150°C

This is the clearest upgrade trigger. L80 13Cr's passive film becomes increasingly unstable above approximately 150°C, and localised pitting rates increase sharply. Super 13Cr's nickel and molybdenum additions stabilise the passive film at higher temperatures, extending reliable corrosion resistance to 175–200°C.

If the bottomhole temperature is above 150°C and CO₂ is present at meaningful partial pressure, Super 13Cr is the correct specification. No further analysis is needed.

2. CO₂ partial pressure above 3–5 bar

At CO₂ partial pressures above approximately 3–5 bar, the dissolution of CO₂ in water produces carbonic acid concentrations that begin to challenge L80 13Cr's passive film, particularly at elevated temperature. Super 13Cr's molybdenum content significantly improves resistance to this attack.

The interaction between CO₂ partial pressure and temperature is critical — a well at 100°C with 8 bar CO₂ may be within L80 13Cr's envelope, while the same CO₂ partial pressure at 160°C would require Super 13Cr. Always evaluate temperature and CO₂ pressure together.

3. Required yield strength above 80 ksi

L80 13Cr is limited to 80 ksi minimum yield. For deep wells where collapse, burst, or axial loads require more than 80 ksi, L80 13Cr cannot provide the required pressure containment regardless of the corrosion environment. Super 13Cr at 110 ksi provides the mechanical performance of P110 with the corrosion resistance appropriate for CO₂-corrosive wells.

When L80 13Cr Is Sufficient

L80 13Cr is the correct and more economical choice when:

• Well temperature is below 150°C throughout the tubing string
• CO₂ partial pressure is below 3 bar
• Chloride concentrations are moderate (below approximately 30,000–50,000 ppm)
• Required yield strength does not exceed 80 ksi
• H2S partial pressure is within L80 13Cr's NACE MR0175 qualified envelope

Many gas condensate wells in Africa and Southeast Asia fall within this envelope — particularly fields with moderate CO₂ and shallow to medium depth. Specifying Super 13Cr for these wells adds cost without improving well integrity.

Corrosion Qualification — What to Request from the Mill

Neither L80 13Cr nor Super 13Cr should be specified based on generic corrosion resistance claims. Request corrosion qualification data that covers the specific well conditions:

Generic brochure data is insufficient — request test reports from the mill for conditions that bracket your well parameters.

Connection Selection

For both grades in gas condensate service, premium metal-to-metal seal connections are the correct specification. The gas-tight seal requirement in gas production eliminates API thread compound-dependent connections from consideration.

Mixed-Grade String Design

A practical approach for wells with variable temperature profiles along the tubing string is to use L80 13Cr in the cooler upper section and Super 13Cr in the hotter lower section, with the grade transition point determined by the 150°C isotherm in the wellbore.

This approach:

• Minimises Super 13Cr footage to only the sections where it is genuinely required
• Reduces overall tubing string cost compared to full Super 13Cr
• Requires careful connection compatibility verification at the grade interface
• Needs clear marking and handling procedures to prevent mixing during running

The cost saving from a mixed string is significant for deep wells — sometimes 20–30% of the total tubing cost.

Procurement Checklist

References

• API Specification 5CT — Specification for Casing and Tubing
• ISO 13680 — CRA Seamless Tubes for Use as Casing, Tubing and Coupling Stock
• NACE MR0175 / ISO 15156 — Materials for Use in H2S-Containing Environments
• EFC Publication 16 — Guidelines on Materials Requirements in H2S Environments