Casing Pipe — Complete Guide to Grades, Sizes, and Selection

Casing pipe is the steel pipe that lines the wellbore in oil and gas wells. It is run in sections from surface to progressively deeper formations, cemented in the annular space between pipe and formation wall, and left permanently in place. Every well contains multiple casing strings — typically three to five — with outside diameters ranging from 4½ inches (114.3 mm) for production and liner casing to 20 inches (508 mm) or larger for conductor casing at surface. The casing string must withstand the full range of downhole loading: collapse from external formation pressure, burst from internal wellbore pressure, and axial tension from suspended string weight.

API Specification 5CT / ISO 11960, in its 11th edition published December 2023, defines the governing specification for casing and tubing across 15 grade designations. Minimum yield strength ranges from 276 MPa (H40) to 862 MPa (Q125). ZC Steel Pipe manufactures API 5CT casing pipe across the full grade range from J55 through Q125, with outside diameters from 4½ to 20 inches, supplying oil and gas projects across Africa, the Middle East, and South America.

1. What Is Casing Pipe?

Casing pipe lines the drilled wellbore. After each borehole section is drilled, a casing string is lowered on threaded joints to the bottom of the section and cemented by pumping slurry down through the pipe and back up into the annulus between pipe and formation. The hardened cement bonds casing to the rock, providing both mechanical support and a permanent pressure seal.

Casing pipe serves four core functions:

• Wellbore integrity: Prevents collapse of weak formations that would otherwise close in around the drill string or completion equipment.
• Zonal isolation: Seals separate pressure zones from one another, prevents cross-flow between formations, and protects shallow freshwater aquifers from contamination by deeper fluids.
• Pressure containment: Contains wellbore pressure during drilling (kick containment) and during production — full tubing pressure reaches the casing in the event of a tubing failure.
• Wellhead foundation: Provides the structural base for wellhead equipment and blowout preventers at surface.

Casing is distinct from production tubing — the smaller pipe run inside the production casing to carry reservoir fluids to surface — and from drill pipe, the rotating string used during drilling. Unlike tubing, casing is cemented in place and is not retrieved under normal operations.

2. API 5CT 11th Edition — Governing Standard

API 5CT / ISO 11960 is the primary standard governing oil field casing and tubing. The 11th edition, published December 2023, defines:

• Grade designations and group classifications (Groups 1–4)
• Chemical composition and heat treatment requirements
• Mechanical property requirements: yield, tensile, hardness, and elongation
• Dimensional tolerances: OD, wall thickness, weight, length, and straightness
• Product Specification Levels PSL-1 and PSL-2
• Testing requirements: hydrostatic test, tensile test, Charpy impact (PSL-2), and hardness survey

PSL-1 vs PSL-2: PSL-1 is the baseline level. PSL-2 adds mandatory full-length non-destructive examination (NDE) of the pipe body and ends, Charpy V-notch impact testing, per-joint traceability, and tighter dimensional tolerances. PSL-2 is required for sour service, high-pressure gas wells, and HPHT applications. Most international oil company project specifications require PSL-2 as a minimum for production strings.

The standard covers casing (4½ to 20 inch OD) and tubing (1.050 to 4½ inch OD) in the same document. Both product types use the same grade system and mechanical property tables.

3. Casing Pipe Grades — Full Range

API 5CT 11th edition defines 15 grade designations across four groups, covering yield strengths from 276 MPa to 862 MPa. The table below summarises all 15 grades with minimum yield and service classification. All values sourced from API 5CT 11th edition Table C.5.

The hardness column matters more than it appears in a table scan. For the sour service grades, the HRC limit is not a quality indicator — it is the NACE MR0175 / ISO 15156 qualification criterion. Pipe above the limit is not defective under API 5CT; it is simply not usable in H₂S service. This distinction is what creates the T95 hardness trap described in Section 5.

CO₂ corrosion grades: L80-3Cr, L80-9Cr, and L80-13Cr are chromium-alloyed variants designed to resist CO₂ (sweet) corrosion. They carry the same 23.0 HRC hardness limit as L80-1, and the stencil reads "L80" — but they are not qualified for H₂S sour service environments. L80-1 is the only sour service grade in the L80 family.

For full mechanical properties including tensile, hardness, elongation factor, and chemistry limits, see the API 5CT complete specification tables →

For grade-specific selection guides: L80 casing — sour service · OCTG sour service grade selection →

4. Casing Pipe Sizes — From 4½" to 20"

API 5CT defines 15 standard outside diameters with 99 size/weight combinations in total. The table below covers eight representative sizes commonly specified in well programs, showing the weight range and typical grades at each OD.

The nominal weight (lb/ft or kg/m) listed in API 5CT Table C.18 includes the weight contribution of threads and coupling — it is higher than the plain-end weight (Wpe), which covers the pipe body only. Use nominal weight for string weight and handling calculations. Use plain-end weight for body strength calculations (burst pressure, collapse resistance, tension yield).

At any given OD, selecting a heavier weight increases collapse and burst resistance but reduces the internal drift diameter. The drift diameter is the minimum ID that a mandrel must pass through the full pipe length — all planned downhole tools, perforating guns, and completion strings must fit within this dimension. Choosing wall thickness is never a one-variable decision.

Worked Burst Calculation — Grade and Wall in Practice

Grade and wall thickness together determine pressure ratings. The Barlow formula per API 5C3 is: P = 0.875 × (2 × SMYS × t / OD), where the 0.875 factor accounts for the 12.5% wall thickness manufacturing tolerance permitted under API 5CT.

Three representative cases show how grade and string position interact:

• 13-3/8" 68 lb/ft J55 surface casing: t = 0.480 in, P_burst = 0.875 × (2 × 55,000 × 0.480 / 13.375) = 0.875 × 3,955 = 3,460 psi. Sufficient for surface casing rated to protect a 2,000 psi kick scenario at the BOP.
• 7" 26 lb/ft L80 production casing: t = 0.362 in, P_burst = 0.875 × (2 × 80,000 × 0.362 / 7.000) = 0.875 × 8,274 = 7,240 psi. Sufficient for most intermediate-depth production strings with well-understood reservoir pressure.
• 7" 23 lb/ft P110 production casing: t = 0.317 in, P_burst = 0.875 × (2 × 110,000 × 0.317 / 7.000) = 0.875 × 9,946 = 8,703 psi. Required when reservoir pressure exceeds what L80 can cover at practical wall thickness.

The L80 vs P110 comparison at 7" illustrates a common design decision: the P110 string uses a lighter wall but delivers 20% more burst resistance. The tradeoff is that P110 is not a sour service grade. When H₂S is present and the reservoir requires 8,703 psi burst, the design must move to T95 or C110 rather than P110 — which typically means a heavier wall and a higher material cost, because the sour grades operate at lower allowable hardness and yield ranges. Use the Barlow pressure calculator → to run these comparisons for specific size/weight combinations.

For the complete 99-row dimensions table including wall thickness, ID, drift diameter, nominal kg/m, and plain-end kg/m, see API 5CT casing sizes and dimensions →

5. Sour Service vs CO₂ Corrosion vs Standard — Selection Logic

Grade selection begins with the well's corrosion environment. Three distinct categories apply different grade families and different qualification requirements.

Standard (sweet) service: H₂S partial pressure below 0.05 psia (0.0003 MPa) — the NACE MR0175 / ISO 15156 sour service threshold. Use H40, J55, K55, N80, R95, P110, or Q125. No hardness or heat treatment restrictions specific to corrosion service apply. Grade selection is driven by depth, pressure, temperature, and cost.

Sour service — H₂S environments: When H₂S partial pressure exceeds 0.05 psia, the well is sour service. High-strength steel is susceptible to sulfide stress cracking (SSC) — a hydrogen embrittlement mechanism that can cause brittle fracture at loads well below the material's yield strength. Four API 5CT grades are qualified for sour service per NACE MR0175 / ISO 15156:

• L80-1 PSL-2, max 23.0 HRC: mild to moderate H₂S, the workhorse sour casing grade
• C90 PSL-2, max 22 HRC (NACE): moderate sour service, higher strength than L80
• T95 Type 1 PSL-2, max 22 HRC (NACE): moderate to severe sour — see the hardness trap note below
• C110 PSL-2, max 29.0 HRC: severe sour service at P110 strength level; the highest-rated sour grade in API 5CT

The T95 hardness trap: API 5CT permits T95 pipe up to 25.4 HRC, but NACE MR0175 / ISO 15156 requires a maximum of 22 HRC for sour service qualification. Pipe that passes mill inspection at 25.4 HRC fails NACE qualification. The gap between 22.0 HRC and 25.4 HRC is not a margin — it is the difference between qualified and unqualified material for H₂S service. Always specify "T95 Type 1 PSL-2, maximum 22 HRC per NACE MR0175 / ISO 15156" in the purchase order. See the NACE hardness trap guide for the full analysis.

CO₂ corrosion — sweet wells with CO₂: L80-3Cr, L80-9Cr, and L80-13Cr use chromium alloying to resist CO₂ corrosion in sweet wells with no significant H₂S. Chromium forms a passive film that resists CO₂ attack and chloride pitting. The correct variant follows CO₂ partial pressure and chloride concentration — L80-3Cr for mild CO₂, L80-13Cr for aggressive CO₂ and gas condensate environments.

For a complete grade escalation guide by H₂S partial pressure, including the NACE step chart, see OCTG sour service grade selection →

When NOT to Escalate Grade Without Running the Design

Grade escalation is not inherently conservative. Each step up the API 5CT grade ladder changes not just yield strength but also chemistry, heat treatment, and service classification — and creates new vulnerabilities while solving old ones.

The appropriate trigger for grade escalation is a casing design calculation showing the lower grade cannot meet load requirements with practical wall thicknesses and safety factors — not conservative instinct or unfamiliarity with the lower grade's actual limits.

Named Failure Modes

SSC from Grade Substitution — L80-13Cr Used in Sour Service

Mechanism: L80-13Cr's chromium-alloyed microstructure resists CO₂ corrosion through passive film formation. In H₂S environments, atomic hydrogen generated by sulphide corrosion reactions penetrates the passive film and diffuses into the steel matrix, causing stress corrosion cracking at stress concentrations — thread roots, perforation tunnels. The failure mode is the same as standard SSC but occurs at lower H₂S partial pressures than for carbon steel: the passive film acts as a hydrogen concentrator rather than a barrier.

Diagnostic: Brittle cracking at connection thread roots or perforation tunnel edges, correlated in time with H₂S first detection. Unlike carbon steel SSC, corrosion pitting may be absent because the 13Cr grade resisted the electrochemical corrosion but not the hydrogen uptake. The absence of visible corrosion damage is often taken as evidence the grade is performing — it is not.

Fix: Pull the string and replace with a NACE MR0175-qualified sour service grade (L80-1, C90, or T95 per H₂S severity). There is no in-hole remediation for this failure mode.

T95 Hardness Trap SSC

Mechanism: API 5CT permits T95 up to 25.4 HRC. NACE MR0175 / ISO 15156-2 requires ≤22 HRC for carbon steel in sour service. A T95 string delivered at 24 HRC meets the API specification and passes mill inspection but fails NACE qualification. In H₂S service, material at 24 HRC exhibits meaningfully higher SSC susceptibility than material at ≤22 HRC — the 3.4 HRC gap is not a margin, it is the difference between qualified and unqualified material.

Diagnostic: SSC cracking on T95 pipe in a sour well where hardness was not explicitly limited to 22 HRC on the purchase order. MTC review shows hardness 22.5–25.4 HRC — conforming to API 5CT but not to NACE. The MTC is technically clean, which makes the root cause harder to trace.

Fix: If hardness exceeds 22 HRC on the delivered material, the pipe cannot be used in sour service. Prevention is the only viable path: specify "T95 Type 1 PSL-2, maximum hardness 22 HRC per NACE MR0175 / ISO 15156" on every sour service purchase order. Do not rely on the mill applying the NACE limit unless it appears on the PO.

6. Casing String Design — Surface, Intermediate, and Production

A conventional oil or gas well contains three to five casing strings, run in a telescoping sequence — each smaller OD than the string above, each cemented before the next section is drilled.

Conductor casing (16"–30" OD): The shallowest and largest string. It prevents cave-in of unconsolidated near-surface formations, carries the weight of subsequent casing strings and wellhead equipment, and provides the structural base for the BOP stack. Conductor is often driven or jetted rather than drilled and cemented. Typical depth: 30–200 m. Common grades: H40, J55, K55.

Surface casing (10¾"–20" OD): Cemented to surface through shallow formations. Its primary purposes are protecting freshwater aquifers and providing a pressure-rated BOP mounting point before drilling into zones with elevated formation pressure. Surface casing design is governed by the burst load from a worst-case kick scenario — a gas-filled wellbore with full reservoir pressure at the shoe. Typical depth: 300–1,000 m depending on regional geology. Common grades: J55, K55, N80.

Intermediate casing (7"–13⅜" OD): Run to isolate complex sections between surface and the reservoir — abnormal pressure transitions, unstable shale sequences, severe lost circulation formations, salt sections, and other intervals that require isolation before drilling can continue. One or more intermediate strings may be needed in deep or geologically complex wells. Common grades: N80, L80, P110.

Production casing (4½"–9⅝" OD): The innermost string, set across the producing reservoir. Production casing design is the most demanding: it must withstand collapse from a depleted reservoir, burst from a worst-case tubing failure delivering full reservoir pressure to the casing, and axial tension from its own suspended weight plus any buckling or thermal loads. Grade selection here is most sensitive to H₂S content, CO₂ partial pressure, reservoir temperature, and well pressure. Common grades: L80, C90, T95, P110, C110.

Liner strings: A liner does not extend back to surface — it hangs from the previous string via a liner hanger, overlapping the shoe of the previous string. Liners reduce material cost in deep wells by avoiding a full-length string to surface. The liner overlap section must provide adequate cement coverage for annular integrity.

For the engineering basis of casing string design — collapse, burst, and tension safety factors — see casing design basics — collapse, burst, and tension

7. How to Specify Casing Pipe — Procurement Checklist

A complete purchase order for API 5CT casing pipe must cover the following. Omissions lead to non-conforming supply, delays, or rejection on receipt.

The Wrong PO and the Right PO

Wrong: "200 joints 7" casing, N80, BTC, Range 3."

This order is missing the delivery condition (N80-1 or N80Q), PSL level, and any sour service statement. The mill is entitled to supply normalized N80-1 at PSL-1 with no full-length UT and no hardness data. If H₂S is present, the pipe is the wrong grade — N80-1 is not NACE-qualified. If PSL-2 NDE was assumed by the drilling contractor, the pipe has no full-length ultrasonic inspection and no per-joint traceability.

Correct: "200 joints 7" 26 lb/ft API 5CT N80Q PSL-2, BTC connection, Range R3. EN 10204 3.1 MTC with Q+T heat treatment confirmation. Full-length UT per API 5CT Section 10.15.2."

The difference is three lines of text on the purchase order. The cost of correcting a non-conforming shipment at the port — demurrage, reinspection, grade renegotiation — routinely exceeds the cost of the extra specification language.

Dimensions

• Outside diameter: in inches (e.g., 9⅝")
• Nominal weight: in lb/ft (e.g., 47.0 lb/ft) — this uniquely identifies wall thickness, ID, and drift at a given OD
• Length range: R1 (4.88–7.62 m), R2 (7.62–10.36 m), or R3 (11.58–13.72 m); R3 is standard for most casing strings

Grade and Heat Treatment

• Grade: full designation including type and variant (e.g., L80-1, T95 Type 1, N80Q, L80-13Cr)
• PSL level: PSL-1 or PSL-2
• Heat treatment: N80-1 may be N+T or Q+T; all sour service grades (L80-1, C90, T95, C110) require Q+T only

Connection

• Connection type: STC, LTC, BTC (API 5B) or named premium connection
• Coupling material: should match pipe grade or specify upgrade for sour service
• For gas wells or deviated wellbores: specify premium with metal-to-metal seal and ISO 13679 / API 5C5 qualification envelope

Testing and Inspection

• Hydrostatic test: per API 5CT Section 10.12, or elevated mill test pressure if project specification requires
• NDE: full-length UT or EMI required for PSL-2; specify if required for PSL-1
• Charpy V-notch impact testing: mandatory PSL-2; specify test temperature and minimum absorbed energy (transverse or longitudinal)
• Hardness: for T95 in sour service explicitly state "max 22 HRC per NACE MR0175 / ISO 15156"

Sour Service Requirements (When Applicable)

• NACE MR0175 / ISO 15156 compliance statement
• Maximum HRC limits per NACE (not API 5CT alone — for T95 these differ)
• Restricted sulfur/phosphorus chemistry if required by project specification

Documentation

• Mill test report (MTR) per heat: chemistry, heat treatment record, mechanical test results
• Hydrostatic test record per joint (PSL-2)
• Third-party inspection certificate (SGS, BV, TÜV, DNV) if required by operator

For standard casing length ranges and coupling dimensions, see oil casing length ranges — R1, R2, R3

8. Sourcing API 5CT Casing — What the Supply Chain Looks Like in Practice

China is a major global producer of API 5CT casing and tubing. Licensed Chinese mills supply IOC and NOC projects across Africa, the Middle East, and South America under the same API 5CT specification, PSL requirements, and third-party inspection regime as Western producers.

The orders we receive from West African operators for production casing tend to be more specification-complete than orders from the same region for surface casing. Surface casing is often ordered as "J55 BTC" with minimal additional detail, because the string is not the critical barrier. Production casing orders from the same operators typically specify PSL-2, EN 10204 3.1 MTC with heat treatment confirmation, full-length UT, and Charpy V-notch data at the project's minimum temperature. That gap in specification discipline — detailed on the critical string, loose on the less-critical string — is where non-conformance occurs most often. We flag underspecified surface casing orders before manufacturing begins, but not every mill will.

ZC Steel Pipe holds an API 5CT manufacturing licence and produces the full grade range from J55 through Q125 — including sour service grades L80-1, C90, T95, and C110, and all three chromium L80 variants (3Cr, 9Cr, 13Cr) — without grade-specific subcontracting. Witness inspection at the mill by SGS, Bureau Veritas, TÜV, or DNV can be arranged for any order. Mill test records, hydrostatic test data, and dimensional inspection reports are provided with every shipment as standard.

To request a quote, contact Hazel Wang at hazel.w@zcsteelpipe.com or WhatsApp +1-213-239-3018. Provide OD, weight, grade, PSL level, connection type, quantity, and destination port for a response within one business day.