Casing String Design for EPC Engineers: Step-by-Step Guide

Casing design sits at the intersection of drilling engineering and procurement. The drilling engineer computes loads; the procurement engineer sources the pipe to resist them. When these two functions are separated — as they commonly are in EPC contracts — errors enter the material requisition. A production casing specified as "P110, 7 inch, 26 lb/ft, BTC" passes through procurement without anyone noticing that the well has 800 ppm H₂S at depth, and that P110 is not qualified for sour service.

ZC Steel Pipe supplies casing to drilling programmes across sub-Saharan Africa, the Middle East, and Southeast Asia. The most expensive MRQ mistakes we see are grade errors on the production string and connection selection errors on deviated wells — both recoverable before manufacturing, neither recoverable once the string is run. This guide follows the design sequence from top to bottom.

The Four Standard Casing Strings

A conventional vertical or near-vertical well uses four strings of casing, each serving a different structural and pressure-isolation function. The programme may collapse to three strings (eliminating the intermediate) on shallow sweet wells, or expand to five on HPHT deepwater wells.

Conductor Pipe

Size: typically 20–36 inches OD. Set depth: 30–150 m. Function: structural support for the wellhead and surface equipment, protection against shallow washout and gas migration. Conductor is usually driven or jetted — rarely rotated — and cemented from shoe to surface. Grade is typically J55 or K55; dimensional tolerance is less critical than for deeper strings because loads are primarily vertical compression from wellhead weight. Connections are commonly STC (short thread coupling) or plain end with field welding.

Surface Casing

Size: typically 13-3/8 or 16 inches OD. Set depth: 300–600 m. Function: fresh water zone isolation (regulatory requirement in most jurisdictions), structural support for the BOP stack, blowout prevention through its rated working pressure. Surface casing must be cemented to surface and pressure-tested. Grade is typically J55, K55, or N80-1, depending on shallow collapse and burst requirements. If a shallow gas zone exists above the kick-off point, N80Q adds collapse resistance without requiring premium connections.

Intermediate Casing

Size: typically 9-5/8 or 10-3/4 inches OD. Set depth: variable — run as needed to case off abnormally pressured zones, lost circulation intervals, or unstable shales. Intermediate casing may be eliminated if the pore pressure gradient is consistent from surface to reservoir. Grade is driven by collapse at depth and burst at the wellhead: N80, L80, or P110 are the typical range. Sour service gas caps above the reservoir may require L80-1 even on an intermediate string.

Production Casing

Size: typically 7 or 5-1/2 inches OD. Set depth: reservoir. Function: primary pressure barrier for the life of the well. This is the string where grade selection matters most, because it is exposed to the full reservoir pressure and temperature during production. The design load analysis below uses the production string as the worked example.

The Three Design Load Cases

Casing is designed against three independent load conditions. The governing load — the one that controls grade and weight selection — varies by string position and well type.

Collapse

Definition: External pressure minus internal pressure. Collapse governs when the pipe interior is at lower pressure than the formation fluid acting externally.

Critical scenario: The production string collapses if formation pressure is high and the casing is depleted or lost circulation fluid is replaced by gas. For the design case, most operators use full evacuation — zero internal pressure — with external load equal to the estimated pore pressure gradient at the shoe. This is conservative; some operators use a partial evacuation scenario if the well will not experience full evacuation in its life.

API 5C3 collapse formula regime: The applicable formula (yield-strength, plastic, transition, or elastic) is selected based on the D/t ratio. For 7-inch 26 lb/ft casing (OD = 7.0 in, wall = 0.362 in), D/t = 7.0 / 0.362 = 19.34.

For N80Q (Grade L-N-80 in API 5C3):

• D/t boundaries from API 5C3: (D/t)_YP = 13.38, (D/t)_PT = 22.47, (D/t)_TE = 31.02
• D/t = 19.34 falls between (D/t)_YP and (D/t)_PT → plastic collapse regime

Plastic formula: Pp = Yp × [A / (D/t) − B] − C

Using L-N-80 coefficients from API 5C3 (A = 3.071, B = 0.0667, C = 1,955): Pp = 80,000 × [3.071 / 19.34 − 0.0667] − 1,955 = 80,000 × [0.1589 − 0.0667] − 1,955 = 80,000 × 0.0922 − 1,955 = 7,376 − 1,955 = 5,421 psi (37.4 MPa)

This is the minimum collapse resistance of 7-inch 26 lb/ft N80Q before axial load correction. An axial tension load in the string will reduce this value further — use the axial stress correction formula in API 5C3 Section 2.1.5 for the actual string.

Burst

Definition: Internal pressure minus external pressure. Burst governs when reservoir fluid enters the casing at high pressure while the external annulus fluid pressure is low.

Critical scenario: Gas kick at the wellhead with full shut-in surface pressure. Burst pressure at the wellhead = shut-in wellhead pressure (SIWHP). For a well with 690 bar (10,000 psi) BHSIP, 4,500 m TVD, and a gas gradient of 0.1 psi/ft, SIWHP ≈ 10,000 − (0.1 × 4,500 × 3.281) = 10,000 − 1,476 = 8,524 psi (587 bar) at the wellhead. This is the burst load the production casing must resist at the shoe-to-wellhead section.

Minimum burst resistance (API 5C3): For 7-inch 26 lb/ft N80Q:

Pb = 0.875 × 2 × Yp × t / D = 0.875 × 2 × 80,000 × 0.362 / 7.0 = 0.875 × 8,274 = 7,240 psi (49.9 MPa)

N80Q at 7" 26 lb/ft does not meet the burst requirement for a well with 590 bar SIWHP at the wellhead. The calculation tells you to step up to a heavier weight or higher grade.

For P110 at 7" 26 lb/ft (same wall 0.362"): Pb = 0.875 × 2 × 110,000 × 0.362 / 7.0 = 0.875 × 11,377 = 9,955 psi (68.6 MPa) ✓ — meets the burst requirement with a safety factor of 9,955 / 8,524 = 1.17.

Tension

Definition: Axial tension load from the weight of the string in air, adjusted for buoyancy in drilling fluid, plus overpull. Tension governs typically at the top of the string.

Minimum tensile resistance (pipe body yield): T = Yp × A_s

Where A_s = cross-sectional area of pipe wall.

For 7-inch 26 lb/ft: A_s ≈ 7.549 in² (from API 5CT tables)

N80Q pipe body yield tension: T = 80,000 × 7.549 = 603,920 lbf (2,686 kN) P110 pipe body yield tension: T = 110,000 × 7.549 = 830,390 lbf (3,694 kN)

String weight in 14 ppg mud at 4,500 m (14,764 ft): approx. 26 × 14,764 × (1 − 14/65.4) ≈ 26 × 14,764 × 0.786 ≈ 301,730 lbf

Design tension = string weight + overpull (typically 100,000 lbf). For P110, design tension safety factor = 830,390 / (301,730 + 100,000) = 830,390 / 401,730 = 2.07 — well above the typical minimum of 1.6.

Grade Selection by String

Numbers from api-5ct-spec.json — API Specification 5CT, 11th Edition.

Two values in this table drive most grade errors: the Max HRC column and the Sour Service flag.

P110 has no hardness limit under API 5CT. A mill can ship P110 at HRC 26 and be fully compliant. NACE MR0175 / ISO 15156-2 requires carbon steel OCTG in H₂S service to not exceed HRC 22. These two facts together mean that P110 — the grade most commonly used for deep wells — cannot be qualified for sour service. There is no PO language that converts P110 into a sour-service grade.

For the complete API 5CT mechanical property and hardness tables, see API 5CT specification tables →

To match well conditions to grade, use the AI Pipe Grade Selector →

Worked Design Example — 7-Inch Production String, HPHT Sweet Well

Well parameters:

• TVD: 4,500 m (14,764 ft)
• BHSIP: 690 bar (10,000 psi)
• BHST: 145°C (293°F)
• H₂S: 0 ppm (sweet)
• Mud weight: 14 ppg (1.68 sg)
• Design factors: collapse 1.0, burst 1.1, tension 1.6

Candidate grade: P110, 7" 26 lb/ft (OD 177.8 mm, wall 9.19 mm)

From the calculations above:

Collapse check: external pore pressure at 4,500 m in 14 ppg formation fluid ≈ 14 × 4,500 × 0.052 × 0.433 ≈ 1,424 psi; full-evacuation collapse load ≈ 1,424 psi. P110 at 6,232 psi comfortably exceeds this. Governs on burst.

Conclusion: 7-inch 26 lb/ft P110 with BTC connection is structurally adequate for this sweet HPHT well. If the well had H₂S at depth, the grade would shift to C110 for the production string — the geometry (7" 26 lb/ft) would remain the same.

Sour Service — What Changes in the Design

When H₂S partial pressure exceeds the threshold in NACE MR0175 / ISO 15156-2 Table 1, the grade selection constraint shifts from yield strength to hardness:

• L80-1: 552–655 MPa yield, max HRC 23 → mild sour service (H₂S moderate, CO₂ low)
• C90: 621–724 MPa yield, max HRC 25.4 → moderate sour service
• T95: 655–758 MPa yield, max HRC 25.4 → moderate-to-severe sour service
• C110: 758–828 MPa yield, max HRC 29 → severe sour service

The hardness limits are process guarantees, not just targets. API 5CT Section 10.7 requires a minimum of five hardness readings per pipe for Group 2 sour grades (L80-1, C90, T95, C110). A shipment where any reading exceeds the grade limit must be rejected regardless of tensile test results.

The procurement implication: sour service strings require additional MTC documentation. An MTC that includes tensile test data but omits the hardness survey is not acceptable for sour service grade acceptance. Check the hardness survey before clearing a sour service heat from the mill.

Connection Selection for the Production String

The connection selection follows the load analysis:

BTC (buttress thread coupling): Adequate for straight or low-deviation (<30° inclination) sweet wells within 7-inch and smaller production strings. API 5CT BTC is the default when combined load envelope calculations show the connection is not the limiting factor.

Premium connection: Required when any of the following apply:

• Deviated well (inclination >30°) where bending adds to axial load
• HPHT well where combined pressure and temperature cycling stresses the makeup
• Gas-tight requirement where thread compound seal is insufficient for sustained gas pressure
• Q125 or C110 grade, where the pipe body strength makes BTC the limiting element of the string

Connection selection must be verified against the full combined load envelope. A connection rated to API 5C5 CAL IV has been tested at the full combination of tension, compression, internal pressure, external pressure, and bending simultaneously — not each load independently.

Purchase Order Guidance

Procurement traps

Trap 1 — Grade not matching service conditions. The most common MRQ error is specifying P110 for a well with low-level H₂S. The correct grade for that combination is C110 (the highest-strength sour-qualified grade) or T95 depending on the calculated load. P110 cannot be made sour-compatible.

Trap 2 — Not specifying PSL level. A PO that reads "7-inch 26 lb/ft P110 BTC" without PSL level defaults to PSL-1. PSL-1 does not require Charpy impact testing for P110 and does not mandate the same NDE scope as PSL-2. For HPHT production strings, specify PSL-2 and the required supplementary requirements (SR2 for Charpy at project temperature, if applicable).

Trap 3 — Wrong MTC specification for sour service. Sour service casing requires EN 10204 3.2 (third-party witnessed) on most projects. An EN 10204 3.1 certificate is mill-issued and does not include independent hardness verification. For any string exposed to H₂S, require 3.2 and name the TPI (SGS, Bureau Veritas, or project-specified).

Field receipt checklist

1. Verify grade and weight against the MRQ — read the pipe body stencil, not just the packing list
2. For sour grades, confirm hardness survey is included in the 3.2 MTC packet and that no reading exceeds the grade limit
3. Thread protectors intact; no thread compound contamination from shipping
4. End bevel condition — no nicks or damage to sealing surfaces, especially for premium connections
5. Measure OD and wall thickness on at least 5% of pipes per heat (more for premium connections)
6. Verify tally — pipe count, total length, and length range against PO

For sour service grade selection and H₂S partial pressure thresholds, see the Sour Service Grade Selector → and the OCTG Sour Service Grade Selection Guide →