14.1 Shut-In Procedures While Running Casing or Liners

Running casing or liners into a wellbore represents one of the most mechanically complex and hydraulically vulnerable phases in well construction. Influxes taken during casing operations account for some of the most challenging well control situations encountered by drilling supervisors. Unlike conventional drillpipe trips, running casing involves massive tubular diameters, narrow annular clearances, enormous hanging weights, complex float equipment, and specialized handling tools.

Under IWCF Level 4 standards (Task Focus TF-0020, Subtopic 45), rig supervisors must master the hydrodynamic forces generated during casing runs, enforce rigorous trip sheet accounting, and execute flawless shut-in sequences when the well displays positive flow.

---

Annular Geometry and Hydrodynamic Surge Dynamics

The fundamental operational challenge during casing operations stems from the annular clearance between the casing outer diameter ($OD$) and the open-hole borehole (or previous casing inner diameter, $ID$). For example, running a $9\text{-}5/8\text{ inch}$ casing ($9.625\text{ in }OD$) inside a $12\text{-}1/4\text{ inch}$ hole ($12.250\text{ in }ID$) yields a diametrical clearance of just $2.625\text{ inches}$ ($1.3125\text{ inches}$ radial standoff). Running a $7\text{-inch}$ liner inside an $8\text{-}1/2\text{ inch}$ hole yields an even tighter radial clearance of $0.75\text{ inches}$.

                    CASING ANNULAR CLEARANCE & SURGE PROFILE

             Wide Clearance (Drillpipe)            Narrow Clearance (Casing)
            ┌───────────────────────────┐         ┌───────────────────────────┐
            │ │       5.0" DP       │ │         │   │       9-5/8" Csg    │   │
            │ │                     │ │         │   │                     │   │
            │ ├─────────────────────┤ │         │   ├─────────────────────┤   │
            │ │    12-1/4" Hole     │ │         │   │    12-1/4" Hole     │   │
            │ │                     │ │         │   │                     │   │
            │ │ Radial Gap = 3.62"  │ │         │   │ Radial Gap = 1.31"  │   │
            │ │ Low Annular Flow    │ │         │   │ High Annular Flow   │   │
            │ │ Low Surge Pressure  │ │         │   │ Massive Surge ECD   │   │
            └─┴─────────────────────┴─┘         └───┴─────────────────────┴───┘

Surge Pressure Mechanics

As the casing descends, it acts as a massive piston, forcing large volumes of drilling mud upward through the restricted annular space. For a closed-ended string in the simple incompressible, uniform-section model, the mean upward annular fluid velocity relative to the stationary hole is:

$v_{\text{annulus}} = v_{\text{pipe}} \times \left( \frac{A_{\text{casing, OD}}}{A_{\text{hole}} - A_{\text{casing, OD}}} \right)$

Because the annular clearance is narrow, the upward fluid velocity is multiplied significantly relative to pipe running speed. This high fluid velocity generates substantial annular friction pressure losses (${\Delta}P_{\text{surge}}$), which act directly downward against exposed formations:

$P_{\text{bottomhole, dynamic}} = P_{\text{hydrostatic}} + {\Delta}P_{\text{surge}}$

$\text{ECD}_{\text{surge}} = \frac{P_{\text{bottomhole, dynamic}}}{0.052 \times TVD}$

Excessive running speed can raise pressure above formation integrity and cause losses. If losses lower the fluid level sufficiently, another permeable zone can become underbalanced and feed the well. Check the actual pressure window; neither losses nor a secondary influx is an inevitable outcome of every surge.

Stopping downward movement removes surge support and may produce a transient pressure change. Pulling casing upward can generate swab pressure, for example when repositioning for a connection or freeing a tight spot. If the annular clearance is tight and the mud has high gel strength, swabbing can draw formation fluids into the wellbore even while running casing.

---

Trip Sheet Accounting: Casing Volume Verification

Accurate volume accounting during casing runs requires distinguishing between closed-ended, open-ended, and self-filling float equipment:

CLOSED FROM BELOW                     FULL EQUAL-LEVEL FILL MODEL
Annular return: inserted OD volume    Internal entry: added internal capacity
Surface fill: separately measured     Net return: inserted steel volume
Differential-fill/restricted tools require their own planned volume balance.

Surface Fill-Up Volume Tracking

When running conventional closed-ended floats, fill from surface at the intervals or continuously as defined by the running programme, accounting for collapse resistance, internal level and well control. If casing is not filled, the enormous hydrostatic pressure of the mud column in the annulus can exceed the casing's collapse resistance rating, causing catastrophic casing collapse downhole.

The volume of mud pumped into the casing ($V_{\text{fill}}$) must be precisely recorded on a dedicated Casing Fill Sheet:

For a fully filled string, with surface fill drawn from the same measured inventory, no transfers/spills and the stated simple equal-density model: $V_{\text{unexplained}}=V_{\text{return}}-V_{\text{surface fill}}-V_{\text{steel inserted}}$

A closed-ended 1000 ft run with 47.1 bbl OD displacement and 38.2 bbl internal fill gives 47.1−38.2−8.9=0 bbl unexplained change. A fully self-filling run returns 8.9 bbl and needs no surface fill, also giving zero. Underfilled strings require the planned actual internal-volume/level change; do not apply the full-fill equation blindly.

Investigate unexplained return/fill deviations or flow while stationary promptly. Reconcile equipment mode, transfers, measured internal levels and normal flowback without delaying the approved containment response to possible influx.

---

Kick Recognition Indicators While Running Casing

Drilling crews often miss casing kicks because mud movement on the rig floor is noisy, irregular, and obscured by mud spills. The primary warning signs of a casing kick include:

1. Flow Over the Bell Nipple While Stationary: Unexplained continued flow after casing movement stops is a positive warning requiring the approved response; distinguish expected transient displacement/flowback from sustained unexplained gain.
2. Discrepancy in Trip Tank / Active Pit Volume: Annular return volume into the trip tank or mud pits exceeds the calculated pipe displacement volume for the number of joints run.
3. Casing Overflow from Inside: If running self-filling or auto-fill floats, an influx entering the annulus can U-tube into the casing string, causing mud to spill violently out of the top of the casing on the rig floor.
4. Inability to Fill Casing: Casing taking less top-fill than expected is an abnormal observation. Check actual shoe entry, float mode, internal level and volume accounting; formation entry is one possible cause, not a unique diagnosis.
5. Unexpected Hook-Load Change: Large gas influxes in the annulus reduce fluid density, increasing the buoyant weight of the casing string and causing the weight indicator to register an unexpected increase in hook load.

---

Step-by-Step Shut-In Protocol: Hard vs. Soft Shut-In

When a kick is confirmed while running casing, the well must be shut in immediately. The physical challenge is that the casing string cannot be closed by standard drillpipe safety valves (TIW valves) without an adapter swage, and the large casing connection cannot be easily stabbed if flow is exiting through the casing bore.

CASING SHUT-IN: PREPARED RIG-SPECIFIC RESPONSE
Recognize unexplained gain/flow and alert the crew
        ↓
Stop movement; space out and support the string as planned
        ↓
Close the designated BOP on the correct casing body
        ↓
Secure the casing IDusing the verified installed closure or compatible swage/FOSV
        ↓
Establish the planned pressure-monitoring path and record volumes/pressures

Conventional Hard-Shut-In Example

Before starting the run, confirm casing/ram sizes, casing collapse and annular-closing limits, space-out, string support and the casing-IDclosure. Keep a compatible tested circulating swage/FOSV, handling equipment and wrench ready.

1. Stop movement, alert the crew, and position/support the casing according to the rig's procedure so the designated preventer closes on a suitable casing body rather than a coupling or running tool.
2. Close the designated annular preventer or correctly sized casing rams promptly to contain annular flow. Do not make manual swage installation an automatic reason to delay annular closure.
3. Secure the casing bore using the verified installed pressure-control device or the compatible circulating swage/FOSV as the plan requires. When stabbing a manual swage/FOSV into a flowing bore, keep the valve open during safe connection makeup, then close it. Account for actual float performance and personnel exposure.
4. In the hard lineup, the selected choke remains closed. Open the planned choke-line valve to the communicating pressure gauge as required; verify the full lineup and closure.
5. Record annular pressure, any valid communicating casing-IDpressure, gain and time history. Continue leak/volume monitoring and compare pressures with the applicable formation and equipment limits. Do not treat a gauge isolated by a valve as well pressure.

The precise coordination and order of simultaneous annular/IDactions belongs to the approved rig plan. The crew must know it before the operation and act promptly when the defined shut-in trigger occurs.

Soft Shut-In Protocol on Casing

Under the soft shut-in method, the choke line HCR valve is opened before the annular preventer is closed, with the hydraulic choke set in the open position. After the annular preventer is closed, the remote hydraulic choke is gradually closed to shut in the well.

The extra choke-closing stage in a soft shut-in can permit additional influx compared with a prompt hard shut-in. IWCF assesses hard-shut-in competence; this does not create a universal casing-operation mandate. Follow the approved rig-specific procedure, equipment lineup and formation-pressure limits.

---

Managing Mud Spills and Casing Fill-Up Tools

During casing runs, large mud volumes can overflow onto the drill floor, creating severe safety and environmental hazards while obscuring kick symptoms.

INSTALLED CASING TOOL: VERIFY ITS ACTUAL FUNCTION
Top-drive/running connection
        ↓
Casing tool: documented grip, fill and circulation capabilities
        ↓
Pressure-rated seal/IDclosure only if specifically fitted, rated and verified
        ↓
Casing string
A fill cup or circulating seal alone is not proof of a shut-in barrier.

Fill-Up Arrangements and Shut-In Readiness

• Conventional fill hose: Plan its safe removal and keep the correct swage/FOSV and handling equipment immediately available. Include exposure to upward flow in the casing-run briefing and drill.
• CRT/FACarrangements: Some installed systems reduce manual handling and provide rated circulation or pressure-control functions. Others provide fill/circulation without a qualified casing-IDshut-in closure. Confirm the exact model, seal/closure, working limits and test evidence, and rehearse the separate annular and IDresponse. A product name does not establish an automatic FOSVor a guaranteed 45 second shut-in.

---

Contingency: Shut In With Casing Off Bottom

Taking a kick when casing is thousands of feet off bottom is one of the most critical well control scenarios. Unlike drillpipe, casing cannot simply be stripped back to bottom with standard procedures.

Why Stripping Casing is High Risk

1. Collar Geometry: Casing couplings (API Buttress, 8-Round, or premium connections) have steep, square or trapezoidal shoulders. Stripping these large upsets through a closed annular preventer can rip the elastomer element from its housing, causing a catastrophic blowout.
2. Centralizers and Scratchers: Casing strings carry bow-spring or solid blade centralizers and scratchers spaced every 1 to 3 joints. Do not attempt to pass incompatible centralizers or scratchers through a closed sealing element; verify the actual assembly and equipment clearance before considering any movement.
3. String Weight: Slacking off a heavy casing string through closed rams risks buckling the string or exceeding the mechanical slip-crushing limits of the casing.

Volumetric Control vs. Bullheading

• Volumetric Method: When circulation is unavailable and gas is migrating, an approved volumetric plan may maintain BHP within a selected window. In the simple vertical, uniform-capacity, negligible-gas-head batch model, first establish the safety margin, then allow the working-pressure increment to develop. Bleed the calculated mud volume while holding the current upper casing-pressure reference; BHP falls by the working increment toward the safety floor, rather than remaining exactly constant.

$V_{\text{bleed}}=\frac{\Delta P_{\text{step}}C_{\text{ann}}}{0.052\rho_{\text{mud}}}\quad[\text{bbl}]$

Here capacity is inbbl/ft and density inppg. Use the applicable fluid/geometry segments and pressure datums, and check formation/equipment limits. Once gas reaches the outlet, use the approved gas-handling or lubricate-and-bleed plan; do not treat direct venting as an automatic next step.

• Bullheading: Sour influx or an inadequate circulation/volumetric window may justify considering bullheading. Check formation injectivity, possible crossflow/broaching, fluid compatibility, available pump capacity and pressure limits before selecting it. Use the engineered route, density, rate and volume programme; do not automatically pump down casing and annulus together or select bullheading solely becauseH₂Sis present or a limit is threatened.