7.1 Running & Pulling Casing and Liner: Swab, Surge, Returns & Shut-In

Running casing or a liner is one of the riskiest routine operations for well control. The IWCF Level 2 syllabus gives it its own topic area because the large-diameter pipe changes almost everything the crew relies on while tripping drill pipe: swab and surge pressures are higher, the trip tank behaves differently, and the equipment used to shut in the well must suit the casing in the slips.

---

Why Large-Diameter Tubulars Raise the Risk

Casing and liners have a much larger outside diameter than drill pipe, so the annular clearance between the pipe and the hole (or the previous casing) is small. For example, 5-inch drill pipe in 8-1/2-inch hole leaves 1.75 in of radial clearance, but 9-5/8-inch casing in 12-1/4-inch hole leaves about 1.3 in, and only about 0.8 in at the couplings.

Small clearance means the mud displaced by the moving pipe must flow through a narrow gap at high velocity, so:

• Surge while running in is much higher than with drill pipe. Running too fast can fracture the formation, especially at the previous shoe, and cause losses; losses lower the fluid level and can then let another zone kick.
• Swab while picking up or pulling casing or a liner is also higher. Pulling casing back out of the hole (for example after a failed run) needs slow, controlled speeds and close monitoring.

Most casing is run with float equipment (a float shoe and float collar) that stops mud entering from below. The string is then closed-ended: each joint pushes its whole closed-end volume of mud out of the well, which increases surge, and the casing must be filled from surface at intervals. Some float equipment is auto-fill: it lets mud enter while running to reduce surge, and is converted to a one-way float before cementing.

Typical controls are set in the casing programme: maximum running speeds (seconds per joint), breaking circulation at planned depths, and filling the casing on schedule.

---

Monitoring Returns When Running Casing

The IWCF syllabus names three tools for monitoring returns while running and pulling large-diameter tubulars:

Worked Example: Expected Returns per Joint

With conventional floats, 9-5/8-inch casing displaces its closed-end volume:

$\text{Closed-end displacement} = \frac{9.625^2}{1029.4} = \frac{92.64}{1029.4} = 0.0900\text{ bbl/ft}$

So each 40 ft joint should push about $40 \times 0.0900 = 3.60\text{ bbl}$ of mud out of the well. If the trip tank gains 4.5 bbl on a joint, the extra 0.9 bbl is unexplained and may be an influx. If it gains noticeably less than 3.6 bbl, mud is being lost to the formation, often because of surge. Either way, stop, tell the Driller, and flow check.

---

Float Failure and Hydrostatic Loss

If the casing is not filled and the float equipment then fails, mud from the annulus U-tubes into the empty part of the casing. The annulus level falls and bottom-hole pressure drops. IWCF's formula sheet gives the hydrostatic pressure loss as:

$\Delta P = \frac{\text{MW} \times 0.052 \times \text{casing capacity} \times \text{unfilled height}}{\text{casing capacity} + \text{annular capacity}}$

Example: 9-5/8-inch casing (capacity $0.0732\text{ bbl/ft}$) in 12-1/4-inch hole (annular capacity $0.0558\text{ bbl/ft}$), with 400 ft unfilled and 12.0 ppg mud:

$\Delta P = \frac{12.0 \times 0.052 \times 0.0732 \times 400}{0.0732 + 0.0558} = \frac{18.27}{0.1290} \approx 142\text{ psi}$

The annulus level falls about 227 ft. If the overbalance was less than 142 psi, the well can kick. Filling on schedule keeps the unfilled height small.

---

Shut-In Procedure When Running Casing

IWCF's syllabus summarises the steps as stop operations, secure the string, shut in the well:

1. Stop operations: stop running and set the casing in the slips or spider with a coupling at a safe working height.
2. Secure the string: install a crossover from the casing thread to a full-opening safety valve (or a circulating head fitted with a valve) and close it. This crossover and valve must be made up and ready on the drill floor before casing running starts.
3. Shut in the well: close the annular preventer (or casing rams, if the stack has been fitted with them for the job), then open the choke-line (HCR) valve against the closed choke.
4. Notify the supervisor, record shut-in casing pressure and pit gain, and monitor the well.

Points specific to casing:

• Pipe rams do not fit casing. Unless casing rams are installed, the annular preventer is the only preventer that will seal around it.
• Annular closing pressure must follow the manufacturer's chart for casing, because excessive pressure can collapse the casing.
• Shear rams may not be able to cut casing, so the plan must say what happens if the annular does not seal.
• When a liner is run on drill pipe, the shut-in uses the annular on the liner while the liner is across the BOP, and the normal drill pipe shut-in (safety valve and pipe rams) once drill pipe is across the stack.

The Level 2 crew's part is the same as on any trip: watch the trip tank and running sheet, report any difference to the Driller at once, and be ready to stab and close the safety valve.