Selecting the wrong OCTG grade is one of the most expensive mistakes in well construction. A casing string that fails downhole — whether by collapse, burst, sulfide stress cracking, or CO₂ corrosion — can mean a full workover, lost production, or an abandoned well. The grade selection decision happens long before the pipe is ordered, and it has to be right the first time.
This guide walks through the complete OCTG material selection process: how to read your well parameters, which API 5CT grades apply to which conditions, when standard carbon steel stops being adequate, and how to match connection type to well design. ZC Steel Pipe supplies the full API 5CT range — J55 through P110, 13Cr, and corrosion-resistant alloys — with mill certification and third-party inspection for global projects.
1. The 5-Parameter Selection Framework
Every OCTG grade selection starts with five well parameters. These must be defined before any grade, weight, or connection can be specified. They are not independent — sour service overrides strength considerations, and temperature overrides standard grade approvals. Work through them in the order below.
01
Depth & Pressure
Sets minimum yield strength requirement. Drives collapse, burst, and tension load calculations under API TR 5C3 or ISO 10400.
02
H₂S Presence
The hard constraint. Any H₂S above NACE thresholds eliminates P110, N80-Q, and all non-hardness-controlled grades immediately.
03
CO₂ Partial Pressure
Drives corrosion allowance or CRA selection. Above ~7 psi (0.5 bar) CO₂, inhibited carbon steel is marginal and 13Cr becomes the economic choice.
04
Temperature (BHT)
Affects grade suitability. 13Cr is limited to ~150°C. HPHT conditions above 150°C / 10,000 psi require special grade and connection qualification.
05
Well Trajectory
Horizontal and extended-reach wells impose high bending loads and torque on connections. API threads are inadequate — premium connections are required.
Field Note — The Sequence MattersAlways evaluate H₂S first. Engineers sometimes select P110 for its strength advantage and then try to apply corrosion inhibitors as a workaround in borderline sour conditions. This is not acceptable under NACE MR0175. If the well has any potential for H₂S breakthrough, the grade must be sour-service qualified from the outset. Retrofitting is not an option once the casing is cemented.
2. API 5CT Casing & Tubing Grades
API 5CT defines the grades, mechanical properties, heat treatment requirements, and testing protocols for all OCTG casing and tubing. The grades span from low-cost shallow-well steels to high-strength alloy grades for deep, demanding environments.
J55
Yield: 379–552 MPa
Tensile: 517 MPa min
Heat treat: Normalized
Hardness control: None
Sweet service only K55
Yield: 379–552 MPa
Tensile: 655 MPa min
Heat treat: Normalized
Hardness control: None
Sweet service only N80 Type 1
Yield: 552–758 MPa
Tensile: 689 MPa min
Heat treat: Normalized
Hardness control: None
Sweet service only N80Q
Yield: 552–758 MPa
Tensile: 689 MPa min
Heat treat: Quenched & Tempered
Hardness control: None
Sweet service only L80 Type 1
Yield: 552–655 MPa
Tensile: 655 MPa min
Heat treat: Quenched & Tempered
Hardness: Max 23 HRC
Sour service qualified L80-13Cr
Yield: 552–655 MPa
Tensile: 655 MPa min
Heat treat: Quenched & Tempered
Hardness: Max 23 HRC
CO₂ / CRA grade T95
Yield: 655–758 MPa
Tensile: 724 MPa min
Heat treat: Quenched & Tempered
Hardness: Max 25.4 HRC
Sour service qualified P110
Yield: 758–965 MPa
Tensile: 862 MPa min
Heat treat: Quenched & Tempered
Hardness control: None
Sweet service only Critical Engineering Point — P110 and H₂SP110 has no hardness ceiling in API 5CT. Actual hardness values frequently reach 28–30 HRC at the upper end of its yield range. NACE MR0175 mandates a maximum of 22 HRC for carbon steel in H₂S service. P110 will fail by sulfide stress cracking (SSC) at H₂S partial pressures above 0.05 psia — this is not a borderline situation, it is a catastrophic failure mode. P110 is strictly for sweet wells. No exceptions.
3. Sweet vs Sour Service: The Most Critical Decision
The distinction between sweet and sour service determines which grades are permissible. It is defined not by whether a well "smells" of H₂S, but by precise thresholds in NACE MR0175 / ISO 15156.
SOUR SERVICE DEFINITION — NACE MR0175 / ISO 15156A well environment is classified as sour if the H₂S partial pressure in the produced gas phase exceeds 0.05 PSIA (0.34 KPA)at any point in the system — and liquid water is present. Both conditions must coexist. A dry gas stream with H₂S above this threshold is not classified as sour for OCTG purposes, but most well environments with water cut qualify.
Sour Service Grade Hierarchy
| Grade | Max Hardness | NACE Approved? | Yield Strength Window | Typical Sour Application |
| L80 Type 1 | 23 HRC | Yes — all regions | Narrow (552–655 MPa) | Standard sour casing and tubing, moderate H₂S |
| T95 | 25.4 HRC | Yes — all regions | 655–758 MPa | Deep sour wells requiring more strength than L80 |
| C110 | 30 HRC | Yes — restricted conditions | 758–828 MPa | HPHT sour — H₂S <0.2 psia, pH >3.5 |
| Q125 | No limit | No | 862–1034 MPa | HPHT sweet only |
| P110 | No limit | No | 758–965 MPa | Sweet only — prohibited in any H₂S |
| N80 | No limit | No | 552–758 MPa | Sweet only |
Procurement Note — The L80 Yield TrapL80's narrow yield window (552–655 MPa maximum) is not just a specification detail — it is a manufacturing constraint that drives cost. Mills must scrap heats that exceed 655 MPa yield to maintain sour service compliance, resulting in significantly higher production cost vs N80 or P110. When a supplier quotes L80 at the same price as N80, ask for the heat treatment records and hardness test certificates. Under-priced L80 is frequently N80 with a relabelled MTR.
For a detailed comparison of the main sour service grades, see: P110 vs L80 vs T95 — Design, Yield Traps and Failure Thresholds →
4. CO₂ Corrosion & When to Choose 13Cr Tubing
CO₂ in produced fluids reacts with water to form carbonic acid, attacking carbon steel from the inside out. Unlike H₂S, CO₂ corrosion does not cause sudden brittle fracture — it causes progressive wall thinning that eventually leads to burst or leak. The selection decision is essentially an economic one: is the cost of inhibitor injection over the well's life less than the cost of 13Cr tubing?
CO₂ Corrosion Rate Guidelines
| CO₂ Partial Pressure | Carbon Steel Risk | Recommended Material |
| < 7 psi (0.5 bar) | Low — inhibition viable | Carbon steel + corrosion inhibitor |
| 7–30 psi (0.5–2 bar) | Moderate — inhibition marginal | 13Cr or inhibited carbon steel (with monitoring) |
| > 30 psi (2 bar) | High — inhibition unreliable | 13Cr or Super 13Cr mandatory |
13Cr Grade Limits — Where It Stops Working
13Cr (L80-13Cr) is not a universal corrosion solution. It has specific environmental limits that must be respected:
Temperature limit: ~150°C (302°F). Above this, the passive chromium oxide film becomes unstable. Super 13Cr extends this to ~180°C.
Chloride limit: ~50,000 ppm Cl⁻. High-chloride environments break down the passive film and cause pitting. Duplex stainless (22Cr or 25Cr) is required above this threshold.
H₂S limit: <0.05 psia H₂S partial pressure. 13Cr is susceptible to SSC at higher H₂S concentrations. For co-production of CO₂ and significant H₂S, Super 13Cr or Duplex is required.
Not suitable for acid stimulation. 13Cr is highly sensitive to spent acid — the passive film is stripped by hydrochloric acid. Acidizing without specifically rated inhibitors causes rapid mass loss.
Engineering Insight — 13Cr vs Inhibited Carbon Steel: The Economic DecisionThe break-even point depends on well life and inhibitor OPEX. For a 20-year producing well with CO₂ partial pressure above 15 psi, the total inhibition cost (chemical, injection equipment, monitoring, workovers for corrosion failures) typically exceeds the 13Cr tubing premium within 4–7 years. For short-life wells or those with low water cut (limiting corrosion rate), inhibited carbon steel remains economic. Always run a 20-year NPV comparison before defaulting to either option.
For the full 13Cr selection guide see: Understanding the Benefits of 13 Chrome (13Cr) Tubing Pipe →
5. HPHT Wells: High-Pressure High-Temperature Selection
High-Pressure High-Temperature (HPHT) is typically defined as bottomhole pressure > 10,000 psi (69 MPa) and/or bottomhole temperature > 150°C (302°F). These conditions impose requirements that standard API grades and connections cannot reliably meet.
HPHT Grade Considerations
Sweet HPHT: P110 is the standard high-strength grade. For extreme depths, Q125 provides higher yield (862–1034 MPa) but requires special connections and handling — it has essentially no ductility reserve and is extremely notch-sensitive.
Sour HPHT: C110 is qualified for limited sour conditions (H₂S < 0.2 psia, pH > 3.5). Above these limits, CRA options such as Super 13Cr, 22Cr Duplex, or nickel alloys must be considered.
Temperature effects on grade: Yield strength decreases with increasing temperature — mechanical design must use derated values at BHT, not ambient temperature properties. API TR 5C3 contains temperature derating factors.
Critical Engineering Point — HPHT Connection IntegrityStandard API threads (STC, LTC, BTC) are not gas-tight and have no reliable seal above moderate pressures. In any HPHT application, premium metal-to-metal seal connections qualified to ISO 13679 CAL IV are mandatory. A single connection failure in a 15,000 psi HPHT well is a well control event. The premium connection cost is negligible against the intervention cost.
6. Connection Type Selection
Grade selection and connection selection are inseparable. The strongest pipe in the right grade will still fail if the connection cannot hold pressure or handle the imposed loads. API 5CT defines four standard API threads; ISO 13679 governs premium connection qualification.
| Connection | Gas-Tight? | Torque Resistance | Suitable For | Not Suitable For |
| STC (Short Round Thread) | No | Low | Shallow sweet wells, surface casing, water | Gas wells, HPHT, sour service, horizontal |
| LTC (Long Round Thread) | No | Low–Medium | Medium-depth sweet oil wells | Gas wells, HPHT, deviated wells |
| BTC (Buttress Thread) | No | High | Deep sweet wells, high axial load strings | Gas wells, HPHT — still not gas-tight |
| Premium (metal-to-metal seal) | Yes | Very High | Gas, HPHT, sour, horizontal, deepwater, offshore | — |
Field Note — BTC Is Not Gas-TightBTC (Buttress Thread Casing) is a widely misunderstood connection. Its asymmetric thread form gives it excellent axial load resistance and it is far superior to STC/LTC for deep casing strings — but it has no metal-to-metal seal. It relies on thread compound to maintain sealing, which degrades over time and under thermal cycling. For any gas well, or any casing string exposed to gas migration, BTC is not acceptable. Specify a premium connection.
For a full breakdown of connection types: Connection Types for Casing and Tubing → | BTC Casing Explained →
7. OCTG Grade Selection Matrix
Use the matrix below as a starting point. Final grade selection must always be confirmed against full wellbore load calculations per API TR 5C3 / ISO 10400 and corrosion engineering review.
| Well Type | H₂S Present? | CO₂ > 7 psi? | Depth / Pressure | Recommended Casing Grade | Recommended Tubing Grade | Connection |
| Shallow onshore sweet | No | No | < 2,000m / low | J55 / K55 | J55 | STC or LTC |
| Medium-depth onshore sweet | No | No | 2,000–4,000m / medium | N80 / L80 | N80 | BTC |
| Deep onshore sweet | No | No | > 4,000m / high | P110 | P110 | BTC or Premium |
| Sour service (H₂S) | Yes | Any | Any depth | L80 Type 1 | L80 Type 1 | Premium |
| Deep sour (high strength needed) | Yes | Any | > 4,000m | T95 | T95 | Premium |
| CO₂-rich gas well (sweet) | No | Yes | Any | L80 / P110 | L80-13Cr | Premium |
| HPHT sweet | No | Possible | > 5,000m / >10,000 psi | P110 / Q125 | P110 / 13Cr | Premium CAL IV |
| Offshore / deepwater | Possible | Possible | High | L80 or P110 | L80-13Cr or T95 | Premium CAL IV |
| Horizontal / shale | Typically No | Typically No | Medium–high | P110 | P110 | Premium (torque-critical) |
Engineering Insight — Don't Over-SpecifyThe most common over-specification error is running premium connections on shallow sweet casing strings where STC or LTC is technically adequate. Premium connections add 30–80% to connection cost per joint. On a 200-joint surface casing string in a straightforward vertical sweet well, that premium buys nothing. Reserve premium connections for where the engineering requires them: gas strings, sour service, HPHT, deviated wells, and any tubing string in a producing gas well.
8. Frequently Asked Questions
How do I choose the right OCTG grade?
Start with five parameters: well depth and pressure (sets minimum yield strength), H₂S presence (the hard sour service constraint), CO₂ partial pressure (drives CRA selection), bottomhole temperature (limits grade and connection options), and well trajectory (horizontal wells require premium connections). Work through these in order — sour service eliminates grades before any other consideration applies.
What is the difference between J55, N80, L80, and P110?
J55 (379 MPa min yield) is for shallow, low-pressure sweet wells. N80 (552 MPa) is a general-purpose intermediate grade for medium-depth sweet service. L80 (552 MPa, hardness-controlled to 23 HRC max) is the entry-level sour service grade approved for H₂S environments. P110 (758 MPa) provides the highest strength for deep sweet wells but is strictly prohibited in any H₂S environment. See also: J55 vs K55 → | N80 vs L80 →
Can P110 casing be used in sour service?
No — under any circumstances. P110 has no hardness ceiling and no NACE MR0175 qualification. It will fail by sulfide stress cracking at H₂S partial pressures above 0.05 psia. Use L80 Type 1 for standard sour service, T95 for deep sour wells requiring higher strength, or C110 for very specific high-pressure sour HPHT conditions. For the full technical analysis: P110 vs L80 vs T95 →
When should I use 13Cr tubing?
L80-13Cr tubing is the correct choice when CO₂ partial pressure exceeds approximately 7 psi (0.5 bar) and H₂S is below NACE thresholds. It provides excellent resistance to CO₂ corrosion without the cost of more exotic alloys. It is limited to approximately 150°C bottomhole temperature and chloride concentrations below ~50,000 ppm. For higher temperatures or chloride environments, Super 13Cr or 22Cr Duplex is required.
What connection type should I specify?
For shallow sweet casing: STC or LTC is adequate. For medium to deep sweet casing with high axial loads: BTC. For any gas well, HPHT application, sour service string, or horizontal well: premium metal-to-metal seal connections qualified to ISO 13679 are mandatory. BTC is not gas-tight and is not acceptable for gas strings regardless of depth.
What is the difference between casing and tubing in OCTG?
Casing is large-diameter pipe cemented permanently into the wellbore to provide structural support, zone isolation, and wellbore integrity. Tubing is smaller-diameter pipe run inside the casing to transport production fluids to surface — it is not cemented and can be retrieved and replaced. Both are governed by API 5CT but have different OD ranges, grade requirements, and connection designs optimized for their respective functions.
Source OCTG from ZC Steel Pipe
ZC Steel Pipe (Zhencheng Steel Co., Ltd.) manufactures and exports the complete API 5CT OCTG range — casing and tubing in J55, K55, N80, L80, L80-13Cr, T95, and P110, with premium connection options including our patented ZC-series gas-tight connections. With over 30 years of production experience and completed projects across Africa, the Middle East, and South America, we provide full mill certification, third-party inspection support, and technical consultation for grade selection on complex wells.
Contact us: [email protected] | WhatsApp: +86-139-1579-1813
→ Request a Quote Related products & articles: API 5CT Casing & Tubing · Premium Connections · N80 vs L80 · P110 vs L80 vs T95 ·
