Casing design is the translation of reservoir data, mud program, and geological risk into a material specification. It answers a specific question: which grade, weight, and wall thickness will survive the worst-case loads at every depth in every phase of the well's life. Get it right and the well is never the constraint. Get it wrong and the consequences range from a workover to a well-control event.
At ZC Steel Pipe, we supply casing strings across the full API 5CT grade ladder — J55 through Q125 — to operators running programs in West Africa, the Middle East, and South America. The grade selection conversations we have with drilling engineers almost always come back to the same three load cases, the same two formulas, and a small set of specification errors that recur across projects. This article covers all three.
The Three Load Cases
Every casing string must satisfy three independent load cases: collapse, burst, and tension. They do not occur simultaneously at peak values, but a casing program must be checked against all three independently, at every depth increment of every string.
Collapse is the net external-over-internal pressure that tends to crush the pipe inward. The critical scenario varies by string type — production casing during a workover with heavy kill fluid inside and depleted reservoir pressure outside, intermediate casing below a lost-circulation zone where mud level has dropped. The API TR 5C3 collapse rating accounts for pipe OD, wall thickness, and yield strength, with the collapse mode (elastic, transition, or plastic) determined by the D/t ratio. Thin-wall pipe collapses in the elastic mode where wall thickness matters more than grade — going from N80 to P110 at high D/t provides almost no collapse benefit. Thick-wall pipe at low D/t collapses plastically, where yield strength is the governing variable and grade selection makes a meaningful difference.
Burst is the net internal-over-external pressure that tends to split the pipe longitudinally. The governing scenario is typically a well-control event — a gas kick with the wellbore full of gas to surface — or a stimulation job that pressurizes the string above its completion design. Burst resistance scales directly with both yield strength and wall thickness, which means higher grade and heavier weight both improve burst performance proportionally.
Tension accumulates from string weight in the mud, buoyancy reduction, bending moment in deviated holes, shock loads during running (pipe set hard in slips), and thermal expansion differentials during production. The maximum tensile load is normally at the top of the string, during the running phase, before cement has set. Both pipe body yield and connection joint yield must be checked against tension safety factors.
Burst Rating — Barlow Formula
The API TR 5C3 burst rating uses the Barlow formula with a 0.875 wall-thickness correction factor, which represents the API 5CT minimum wall tolerance (12.5% below nominal):
P_burst = 0.875 × (2 × SMYS × t / D)
where SMYS is minimum specified yield strength in psi, t is nominal wall thickness in inches, and D is outside diameter in inches.
The 0.875 factor is not a safety factor — it is a correction for the minimum-wall pipe that API 5CT permits. Design calculations must use this corrected formula; using nominal wall without the 0.875 factor produces an unconservative burst rating that overstates the pipe's actual minimum performance.
Worked calculation — 7" 23 lb/ft production casing:
For this common production string size, OD = 7.000 inch, nominal wall t = 0.317 inch.
Comparing N80 (min yield 80,000 psi) against P110 (min yield 110,000 psi):
- N80: P_burst = 0.875 × (2 × 80,000 × 0.317 / 7.000) = 0.875 × 7,246 = 6,340 psi
- P110: P_burst = 0.875 × (2 × 110,000 × 0.317 / 7.000) = 0.875 × 9,963 = 8,720 psi
P110 delivers a 37.5% higher burst rating than N80 in the same 7" 23 lb/ft pipe. If reservoir shut-in pressure at surface is 7,500 psi, N80 does not meet a 1.1 burst safety factor (it would require 8,250 psi rating) — P110 does. This is a typical grade upgrade driver on high-pressure gas wells.
Use the Barlow pressure calculator to run these comparisons for any size and grade without manual arithmetic.
For the full grade ladder with yield, tensile, and hardness limits, see the API 5CT specification tables.
Collapse — The Load Case That Gets Harder Over Time
Collapse is the one load case that gets more dangerous as the well ages. On initial completion, wellbore pressure supports the casing from the inside — reservoir pressure, completion fluid, and wellbore temperature all help. As the reservoir depletes over years of production, that internal support disappears. External pore pressure and formation overburden remain, but the inside of the casing increasingly sees produced fluids at declining reservoir pressure. An N80 production string that passed collapse design on first completion — with a comfortable 1.05 safety factor — can be at the margin of collapse failure a decade later as reservoir pressure drops below mud weight equivalent. This is why operators with long-term production horizons sometimes specify a collapse safety factor of 1.125, not just 1.0, even on wells that look uncritical on day one. The extra 12.5% headroom costs almost nothing in grade selection but covers a depletion scenario the original design may not have modeled.
The API TR 5C3 collapse formulas define four collapse regimes based on D/t ratio: yield-strength collapse at very low D/t, plastic collapse through the transition zone, and elastic collapse at high D/t. For most production casing weights — 7", 9⅝", 13⅜" in typical field weights — the pipe falls in the transition or plastic regime, where both yield strength and wall thickness affect the rating. Moving from N80 to L80 at the same OD and wall provides identical mechanical collapse resistance (both are 80 ksi minimum yield), but moving from N80 to P110 in the same pipe body provides a meaningful improvement in the plastic collapse regime.
The biaxial correction applies here directly: collapse resistance decreases under axial tension. A deep string carrying 200,000 lb of tensile load at the top will have a lower effective collapse rating than the uniaxial API value suggests. For wells below approximately 3,000 m (10,000 ft) with heavy strings, the biaxial correction can reduce effective collapse rating by 10–20% — which can flip a design from passing to failing at the top of string. Check this correction for every deep production casing design.
Tension — String Weight and Biaxial Effects
The tension load at the top of string during running is approximately:
F_tension = (W_air × L) − (W_displaced_mud)
where W_air is the pipe weight per foot, L is the string length, and the buoyancy reduction depends on mud weight and pipe steel density. In practice, drilling engineers use computerized wellbore programs that track tension continuously with depth, but the governing load is always at the surface during running operations.
Shock loads from setting pipe in slips or jarring add dynamic tensile increments above the static string weight. These are typically accounted for with a shock load factor (commonly 1.5× static weight for slips setting, per operator standards). Bending in deviated wells adds additional tensile stress on the high side of the hole at each dogleg — this is computed from dogleg severity in degrees per 100 ft and must be included for wells with significant deviation.
Thermal effects are the tension component most often missed on production casing. When a production string is cemented at ambient temperature and then exposed to hot reservoir fluids, it wants to expand axially. Constrained by cement, it cannot — the result is compressive thermal stress. When production ceases and the string cools, it contracts, generating tensile stress. These thermal cycles can add tens of thousands of pounds of equivalent tension to the string. For wells with large temperature differentials (HPHT wells, steam injection wells, high-GOR wells), the thermal tension increment must be calculated and added to the mechanical design load.
Safety Factors — Standard Values
Minimum industry-standard safety factors across load cases:
| Load Case | Minimum SF | Typical Application |
|---|---|---|
| Collapse | 1.0 | Well-defined collapse load with good mud weight data |
| Collapse | 1.125 | Uncertain collapse load; long-life production wells |
| Burst | 1.1 | Well-controlled wellbore pressures |
| Burst | 1.25 | HPHT, high-GOR, or uncertain formation pressure |
| Tension — pipe body | 1.6–2.0 | 1.8 is the most common operator standard |
| Tension — connection | 1.8 | Based on connection yield efficiency rating |
These are minima. Regulatory authorities in certain jurisdictions (Norway, UK North Sea, Brazil pre-salt) require higher safety factors by law. Project specifications for deepwater, HPHT, or sour service wells routinely mandate 1.25 burst and 2.0 tension even where well conditions would support lower values. The governing standard is always the most conservative among API TR 5C3, the regulatory requirement, and the project specification.
What we see on design reviews: The most common calculation error we encounter on emergency replacement orders is the use of nominal wall thickness rather than minimum wall (nominal × 0.875) in the collapse and burst formulas. The pipe was designed correctly by the original drilling engineer — but a second engineer cross-checking the rating used nominal wall and could not reconcile the numbers, triggering the emergency query. The difference is significant: using nominal wall overstates burst rating by approximately 14% compared to the API minimum-wall formula. Design and verification must both use minimum wall consistently. When we receive an RFQ that references a burst rating we cannot match to the Barlow formula with 0.875 correction, our first question is always which wall thickness was used in the calculation.
Grade Selection by String Type
The grade ladder follows the load profile of each string, from shallow and lightly loaded surface casing to deep, highly loaded production strings.
| String | Typical Grades | Key Constraint |
|---|---|---|
| Surface casing | J55, K55, N80 | Tension from shallow string weight; low burst and collapse loads |
| Intermediate casing | N80-1, L80-1, P110 | Burst from kick containment; sour service → L80-1 only |
| Production casing | L80-1, T95, P110, C110, Q125 | Combined collapse, burst, tension; H2S → sour-qualified grades only |
| Production liner | L80-1, T95, P110 | Same as production casing; tension design differs (hung, not full string) |
Surface casing is typically designed by tension — the string is short and loads are low, so J55 or K55 is almost always sufficient. The upgrade decision to N80 on surface strings usually comes from connection requirements, not pipe body ratings.
Intermediate casing must contain kick pressures from formations below while carrying the weight of production casing above. Burst is the governing load case on most intermediate strings. In sweet (non-sour) service, N80-1 or P110 are the standard choices depending on burst requirement. In any well where H2S has been detected in the interval — or cannot be ruled out — the intermediate string must be L80-1, not N80-1, because N80-1 carries no hardness limit and is not sour-service qualified.
Production casing sees the full combination of all three load cases. The grade selection is driven by whichever load case requires the most capable material — which varies by well depth, reservoir pressure, and H2S content.
When NOT to Use N80 or P110
Both N80 and P110 are widely used grades, but each has specific conditions where they are the wrong choice.
Do not use N80-1 when:
- H2S is in the design basis at any concentration. N80-1 carries no hardness limit under API Specification 5CT, 11th Edition — and no hardness limit means no upper bound on susceptibility to sulfide stress cracking. At a 80 ksi yield grade, N80-1 pipe can exhibit hardness values that fail NACE MR0175 / ISO 15156 requirements. The correct grade for sour service at 80 ksi minimum yield is L80-1, which carries a maximum hardness of 23 HRC.
- The well has a total depth exceeding approximately 10,000 ft with high shut-in wellhead pressure from a gas reservoir. At these conditions, burst and collapse loads both push toward L80 or P110 depending on sour service status — N80 rarely provides adequate margin.
- Reservoir data is incomplete and H2S cannot be excluded from the design basis. Design to the worst credible case; N80-1 is not that grade.
Do not use P110 when:
- H2S is present at any level. P110 is not listed in NACE MR0175 / ISO 15156 for sour service qualification — and it cannot be qualified by heat treatment or hardness testing, regardless of how a supplier proposes to address the gap. The correct grade for high-strength sour service is C110, which shares a similar yield range but carries an explicit NACE qualification with specific chemistry, heat treatment, and hardness requirements.
- The well design applies a burst safety factor below 1.1. P110 is a high-strength grade selected for burst — if the safety factor is compromised elsewhere in the design, the grade choice does not rescue the string.
- Production fluids will contain significant CO2 without inhibition. P110 is a carbon-manganese steel with no corrosion resistance to CO2 — it requires either inhibitor injection or upgrade to a Cr-alloy grade.
For a comprehensive treatment of sour service grade selection across H2S partial pressure and temperature conditions, see our OCTG sour service grade selection guide.
Procurement Trap and Correct PO Language
The most consequential procurement error we have seen in this product category: a production casing string for a gas well where reservoir drill stem test data showed H2S at 50 ppm was ordered as "API 5CT P110." The PO was processed. Mill manufactured to P110. The casing was delivered, inspected, and accepted to P110 — because P110 is what was ordered and P110 is what was shipped. The problem surfaced when the operator's HSE team reviewed the metallurgical traceability package before running the string and noted that P110 is not qualified for sour service under NACE MR0175 / ISO 15156. The string could not be run.
P110 is not sour-service qualified and there is no workaround. A heat treatment that produces 23 HRC maximum hardness would fall outside P110's minimum yield specification. The correct grade is C110 — API Specification 5CT, 11th Edition defines C110 as a sour-service qualified grade with minimum yield 110 ksi / 758 MPa, maximum yield 130 ksi / 896 MPa, maximum hardness 30 HRC, and explicit qualification per NACE MR0175 / ISO 15156-2.
The correct PO line reads: "Casing per API 5CT 11th Edition, Grade C110, [OD] [weight] [connection type], sour service per NACE MR0175 / ISO 15156, EN 10204 3.2 MTC required."
Any PO that reads "P110 sour service" is self-contradicting. No compliant mill can fill that order without violating either the grade specification or the sour service requirement.
Correct purchase order language for sour-service 80 ksi production casing: "API 5CT 11th Edition, Grade L80 Type 1, [OD] [weight] [connection type], NACE MR0175 / ISO 15156 qualified, maximum hardness 23 HRC, EN 10204 3.2 MTC."
Reference Links
Frequently Asked Questions
What are the three primary load cases in casing design?
The three primary load cases are collapse, burst, and tension. Collapse is the external pressure load from formation fluids and mud weight that tends to crush the pipe inward — governing for production casing in deep wells with high mud weights. Burst is the internal pressure load from wellbore fluids and formation pressure that tends to expand the pipe outward — governing for production casing during well control events. Tension is the axial load from the weight of the pipe string, buoyancy, bending in deviated wells, and dynamic loads during running and landing.
What safety factors are used in casing design?
Industry standard minimum safety factors are: collapse — 1.0 to 1.125 depending on certainty of load; burst — 1.1 to 1.25; tension — 1.6 to 2.0 for body yield, 1.8 for joint strength. These are minimum values — project specifications, regulatory requirements, and well criticality often mandate higher safety factors. API TR 5C3 and ISO 10400 provide the recommended design methodology including safety factor guidance.
What is the difference between API collapse rating and actual collapse pressure?
The API collapse rating per API TR 5C3 (formerly API Bull 5C3) is a minimum collapse pressure calculated from pipe dimensions, material yield strength, and empirical formulas accounting for elastic, transition, and plastic collapse modes. The actual collapse pressure of a specific pipe joint may be higher than the API rating due to actual wall thickness and yield strength exceeding the minimum — but design must always use the API minimum rating, not actual pipe properties, unless a full statistical analysis is performed.
How does temperature affect casing design in deep wells?
Temperature increases with depth and significantly affects casing design in two ways. First, elevated temperature reduces steel yield strength — API 5CT specifies ambient-temperature mechanical properties, and corrections must be applied for high-temperature service (typically 0.5–2% yield strength reduction per 50°C above ambient). Second, temperature cycling causes thermal expansion and contraction that generates significant additional axial loads — these must be included in the tension design for production casing subjected to large temperature differentials.
What is biaxial loading and why does it matter?
Biaxial loading refers to the combined effect of axial tension (or compression) and internal/external pressure on the pipe. Under axial tension, the collapse resistance of a pipe is reduced from its uniaxial collapse rating — this is the biaxial collapse effect. Similarly, under high axial tension, the burst resistance is slightly reduced. For deep wells with heavy strings and high pressures, biaxial effects must be included in the design — ignoring them can result in unconservative ratings that appear to meet safety factors when they do not.
What governs the selection between surface, intermediate, and production casing grades?
Surface casing is typically shallow and subject to low loads — J55 or K55 is usually sufficient. Intermediate casing must contain formation pressures while supporting the weight of production casing below — N80 or L80 is common depending on sour service requirements. Production casing is subject to the highest combined loads: collapse from heavy completion fluids, burst from reservoir pressure, and tension from string weight — grades from L80 to Q125 depending on depth, pressure, and H2S content.