Drilling guides › Casing design basics: burst, collapse and tension
Casing design basics: burst, collapse and tension
A casing string has to survive everything the well can throw at it for its whole life: a gas kick while drilling the next section, a lost-circulation event that drains the inside, the weight of the string hanging from the wellhead, and the extra pull needed if it sticks on the way in. Casing design is the job of listing those loads, working out the pressure or force each one puts on every foot of pipe, and picking a grade and weight whose ratings stay comfortably above the loads. This guide covers the three classic checks, burst, collapse and tension, in the simple "uniaxial" form used for first-pass design and for checking someone else's numbers on the rig.
The three loads
Burst
Burst is a net pressure pushing outward: the pressure inside the pipe is higher than the pressure outside it. The worst case is usually a gas kick that fills the casing with gas while the well is shut in. Gas is light, so almost the full formation pressure reaches the top of the string, where there is little or no fluid outside to push back. That is why burst is normally most severe near the surface.
Collapse
Collapse is the opposite: the outside pressure is higher than the inside. The classic case is a partly or fully emptied casing, for example after severe losses or when running pipe without filling it, while the annulus still holds the mud the casing was run in. Outside pressure rises with depth, so collapse is most severe at the bottom of the string. Cementing also loads the lower string in collapse while heavy slurry sits outside lighter displacement fluid.
Tension
Tension comes mainly from the string's own weight, so the top joint carries the most. The load is reduced by buoyancy and increased by drag, shock loads when the slips are set, and any overpull you might need to free stuck pipe. In most strings the weakest point in tension is the coupling (the "joint strength"), not the pipe body.
Formulas used in a first-pass design
0.052 converts ppg and feet to psi, and 65.5 ppg is the density of steel. Pressures are always worked out on true vertical depth, but string weight uses measured length. In metric units the hydrostatic pressure is 0.00981 × density (kg/m³) × depth (m) in kPa.
Design factors
A design factor is the minimum ratio of rating to load that your company accepts. It covers things the simple model leaves out: wear from drill pipe rotating inside the casing, manufacturing tolerance on wall thickness, temperature, and the combined effect of tension and pressure acting together. Each operator sets its own values, but figures in the following ranges are common:
| Load | Typical design factor | Rated value it is compared with |
|---|---|---|
| Burst | 1.0 to 1.25 | Internal yield pressure |
| Collapse | 1.0 to 1.125 | Collapse resistance |
| Tension | 1.6 to 1.8 (or a fixed overpull margin) | Joint strength or pipe body yield, whichever is lower |
Always use the factors in your own company's casing design manual. The point of a design factor is that it is agreed in advance, not picked afterwards to make a string pass.
Reading a casing table
Casing is described by outside diameter, nominal weight per foot, grade and connection, for example "9-5/8 in, 47 lb/ft, N-80, LTC". The grade letter and number give the minimum yield strength in thousands of psi, so N-80 yields at 80,000 psi and P-110 at 110,000 psi. For the same OD, a heavier weight means a thicker wall, a smaller inside diameter and higher pressure ratings. The table below shows typical published API values for 9-5/8 in N-80; confirm figures against the manufacturer's data or your company tables before using them on a well.
| Weight (lb/ft) | Wall (in) | ID (in) | Drift (in) | Collapse (psi) | Burst (psi) |
|---|---|---|---|---|---|
| 40.0 | 0.395 | 8.835 | 8.679 | 3,090 | 5,750 |
| 43.5 | 0.435 | 8.755 | 8.599 | 3,810 | 6,330 |
| 47.0 | 0.472 | 8.681 | 8.525 | 4,750 | 6,870 |
| 53.5 | 0.545 | 8.535 | 8.379 | 6,620 | 7,930 |
The ID is OD minus twice the nominal wall and is what you use for capacity and displacement sums. The drift is the diameter of the gauge mandrel that must pass through every joint; it is the largest tool or bit you can count on running through. Many people pick the next bit from the ID and then find it will not drift. For 9-5/8 in casing the drift is the ID less 5/32 in (0.156 in). The common 8-1/2 in bit passes 40, 43.5 and 47 lb/ft, but not 53.5 lb/ft, whose 8.379 in drift calls for an 8-3/8 in bit.
The burst rating in API tables comes from the Barlow formula with a 12.5% allowance for wall-thickness tolerance:
Collapse ratings come from a set of empirical API equations that depend on the ratio of OD to wall thickness, so they are not worth reworking by hand; read them from the table.
Worked example 1: collapse check and a combination string
9-5/8 in, 47 lb/ft N-80 casing is to be set at 8,000 ft TVD in 11.0 ppg mud. The collapse design case is full evacuation: nothing inside, 11.0 ppg mud outside. The company collapse design factor is 1.125.
The 47 lb/ft pipe is good only down to the depth where the load equals its rating divided by the design factor:
So the bottom of the string is made up of 53.5 lb/ft. With the crossover at about 7,350 ft (rounded up to whole joints), the 53.5 lb/ft section at the shoe has a design factor of 6,620 ÷ 4,576 = 1.45. Putting the heavy pipe only where it is needed is the reason combination strings exist.
Now check the drift. The 53.5 lb/ft joints drift at 8.379 in, so an 8-1/2 in bit for the next section would not pass them. Either the well plan changes to an 8-3/8 in bit, or the bottom section uses a higher grade at 47 lb/ft, which keeps the 8.525 in drift (read its collapse rating from the table and repeat the check). Pressure ratings and drift have to be checked together.
Worked example 2: burst and tension on the same string
The next section will be drilled to 12,000 ft TVD where the pore pressure may reach 12.5 ppg equivalent. The fracture gradient at the 9-5/8 in shoe is 15.0 ppg equivalent. Assume gas at 0.1 psi/ft inside and a 0.465 psi/ft salt-water backup outside.
The formation at the shoe would break down before the surface could see 6,600 psi, so the shoe sets the maximum. Net burst at surface is 5,440 psi (no backup there), giving a design factor of 6,870 ÷ 5,440 = 1.26. At the shoe the net load is 6,240 − 0.465 × 8,000 = 2,520 psi. The string passes a 1.1 burst factor.
Tension at the top joint, using the combination string from example 1:
Even with a 100,000 lb overpull added to the buoyed weight (416,400 lb) the joint strength margin is ample.
Common mistakes
- Checking burst at the shoe only. With a gas-filled string the worst burst load is at the top.
- Using measured depth for pressure in a deviated well. Pressure follows TVD; weight follows measured length.
- Picking the next bit or tool from the ID instead of the drift.
- Forgetting that the connection, not the pipe body, often limits tension.
- Leaving out wear: a long drilling section with high side forces can thin the wall near the top of the string and cut the burst rating.
- Ignoring the collapse load during cementing, when heavy slurry is outside and light displacement fluid is inside.