Casing Design Load Cases for HPHT Wells: Collapse, Burst, and Thermal Loads

Casing failures in HPHT wells cost a lot of money. That is not hyperbole, it is arithmetic. When a string lets go during drilling or completion, you are looking at fishing, sidetracking, or abandonment. Any one of those burns rig time worth several times what the original string cost. And in an HPHT well, a compromised casing barrier does not stay a casing problem — it can climb into a well-control event with consequences that reach well past the wellbore. Here is the part that stings: in most of these failures, the steel was fine. The load cases were not. The design envelope simply missed the stress state the pipe was actually going to see.

Three load families govern HPHT casing design: collapse, burst, and thermal. Below is a worked example for each. Completion engineers picking strings will get something out of it. So will procurement teams who keep asking why a specification reads the way it does.

Standards and Requirements Context

Subsea HPHT casing design has to comply with API 5C3 (Performance Properties of Casing, Tubing, and Drill Pipe) and API TR 5C3 (Technical Report on Equations and Calculations for Casing, Tubing, and Drill Pipe Used as Casing). In the US Gulf of Mexico, BSEE sets the regulatory requirements, and those align with industry standards including API 17TR8 (Recommended Practice for Subsea Wellhead and Christmas Tree Systems) for equipment integration. On methodology: API 5C3 covers performance properties, and the triaxial stress approach used in industry practice comes from API TR 5C3. Know the well-integrity standard for your jurisdiction as well — in the US Gulf of Mexico, that means the BSEE requirements that align with the API 17TR8 framework.

One principle in API 17TR8 matters more than the rest. HPHT wells need a reliability-based or limit-state design philosophy, not simple deterministic design factors. Bolting a scalar safety factor onto a nominal burst or collapse rating does not hold up when temperature-driven property changes and trapped annular pressure arrive at the same time.

Collapse Load Cases

Governing Scenario

Collapse is the external-pressure case. It governs when the pressure outside the pipe beats the pressure inside it. In HPHT wells, the scenario that usually controls is a full or partial evacuation of the string sitting against heavy mud or cement on the outside.

For production casing, the worst case shows up during a lost-circulation event while you are drilling the next section. The annulus is holding a full hydrostatic column of heavy mud, and the casing interior is partly or completely evacuated. There is a second one, and it bites during well kill or workover: you displace the casing interior to a lighter fluid while the cemented annulus keeps its original hydrostatic load.

Salt creep is a separate collapse driver in evaporite sequences. Halite and carnallite do not push back evenly, and they do not push back at a constant rate. The lateral stresses they generate are non-hydrostatic and time-dependent, and they can exceed the collapse rating of a conventionally designed string. If there is salt in the well, the design load has to come out of geomechanical creep data. A fluid-column calculation will not get you there.

Temperature Effect on Collapse Resistance

Hot steel yields earlier. That is the whole point. When you compute collapse resistance at depth, use a temperature-derated yield strength, not the ambient number off the mill certificate. The derating factor depends on the grade, and it needs to come from the tubular manufacturer's qualified test data or from published elevated-temperature tensile data for that specific grade.

Burst Load Cases

Governing Scenario

Burst is the internal-pressure case: inside pressure pushing out past what the pipe can hold. For HPHT production casing, the design-controlling scenario is a gas kick that reaches surface — the "gas-to-surface" or "displacement-to-gas" case. Here the casing has to contain shut-in wellhead pressure with zero credit for external fluid support. You cannot guarantee cement sheath integrity at every depth, so you do not get to count on it.

The second burst case worth running on HPHT completions is a tubing-to-annulus leak near the wellhead. The production tubing springs a leak at or near the surface seal, and now full reservoir pressure is sitting on the inner wall of the production casing. Outside, you have atmosphere. That is the maximum net burst loading the string will ever see.

Worked Example — Net Burst Pressure (Illustrative)

Given:

  • Shut-in tubing-head pressure (SIWHP) from a gas reservoir: P_si
  • Fluid gradient in the casing annulus (assumed gas-filled above leak point): ρ_gas × g × h ≈ 0 (gas gradient is negligible over short depths)
  • Net burst pressure at the wellhead seal: P_net = P_si − P_external

For this illustrative example, assume P_si = 15,000 psi and P_external = 0 psi (atmospheric, no external fluid credited at the wellhead).

Net burst pressure:

P_net = P_si − P_external = 15,000 psi − 0 psi = 15,000 psi

The casing you pick has to have a rated burst resistance exceeding P_net divided by the applicable design factor. Deterministic approach: apply a design factor greater than 1.0 to this value and that gives you the minimum acceptable rated burst resistance. Under the API 17TR8 reliability-based framework, the design factor is replaced by a load resistance factor calibrated to a target reliability level.

One calculation, and you can see why HPHT production casing so often ends up as high-strength, thick-wall pipe. At the wellhead, the net burst load is essentially the full reservoir pressure.

Thermal Load Cases

Why Thermal Loads Are Different in HPHT Wells

In a conventional well, thermal effects on casing are a secondary check. In an HPHT well, they are frequently the primary driver of connection integrity and annular pressure buildup (APB). Trap fluid between two casing strings in a cemented annulus and let production heat it up: pressure climbs fast, because liquids barely compress. API 17TR8 calls APB out explicitly as a critical HPHT-specific load, and it has to be quantified in the design phase.

There is a second effect. When the pipe is constrained at both ends — cemented production casing is the usual example — thermal expansion of the pipe body turns into axial compression. Ignore it and you get buckling or an over-compressed connection.

Multistring Interaction

Heat the intermediate casing during production and it hands load to the surface casing through the cemented annulus. A design that passes every single-string check can still fail once you look at the composite system. This remains true today: any HPHT casing design should carry a coupled multistring thermal-mechanical analysis.

Worked Example — Axial Thermal Load (Illustrative)

Given:

  • Steel modulus of elasticity: E = 30 × 10⁶ psi
  • Coefficient of thermal expansion for steel: α = 6.9 × 10⁻⁶ °F⁻¹
  • Cross-sectional area of pipe body: A (in²)
  • Temperature increase from cementing baseline to production: ΔT (°F)

Axial compressive force generated by thermal restraint:

F_thermal = E × α × A × ΔT

For a pipe with A = 20 in² and ΔT = 150 °F (illustrative values chosen to demonstrate the formula):

F_thermal = (30 × 10⁶ psi) × (6.9 × 10⁻⁶ °F⁻¹) × (20 in²) × (150 °F)

F_thermal = 30 × 10⁶ × 6.9 × 10⁻⁶ × 20 × 150

= 30 × 10⁶ × 6.9 × 10⁻⁶ × 3,000

= 30 × 10⁶ × 0.0207

= 621,000 lbf

Add this compressive load algebraically to the running and pressure-induced axial loads before you check connection ratings. A connection that looks perfectly adequate in tension can be critically loaded in compression the moment you drop the thermal term.

Decision Checklist for HPHT Casing Design

Run this before you finalise a casing design package:

  • Collapse: Has full-evacuation collapse been checked with temperature-derated yield strength at the deepest point of the string?
  • Salt creep: If the well penetrates evaporites, has a time-dependent geomechanical collapse load been incorporated?
  • Burst: Has the gas-to-surface scenario been run with zero external pressure credit at the wellhead?
  • Tubing leak burst: Has the production casing been checked for full reservoir pressure acting at the top of the string?
  • APB: Have all sealed annuli been assessed for trapped fluid pressure rise during production and shut-in? Has a mitigation strategy (foam cement, nitrogen cushion, or burst disk) been selected?
  • Thermal axial load: Has the compressive load from constrained thermal expansion been included in the triaxial stress check?
  • Multistring analysis: Has the design been verified with a coupled multistring model, not just single-string checks?
  • Connection rating: Have connections been verified in combined tension/compression, bending, and internal/external pressure at elevated temperature?
  • Material grade: Has temperature-derated yield strength been confirmed with the manufacturer for the selected grade?
  • Design methodology: Does the design basis align with API 17TR8 reliability targets for the applicable HPHT tier?

Conclusion

Collapse, burst, and thermal loads in HPHT wells interact in ways that conventional single-string, ambient-temperature design methods do not capture. The practical steps forward: make a multistring thermal-mechanical analysis the baseline rather than an optional check, apply temperature-derated material properties throughout, and quantify APB for every sealed annulus before the string design is frozen. On the procurement side, require manufacturer-supplied elevated-temperature performance data as a contract deliverable — not an afterthought. The API 17TR8 framework gives you the reliability-based structure to formalise all of it. Wells that skip these steps do not save engineering time. They transfer cost and risk to the intervention phase, where the bill is always higher.