5.2 Shut-In Procedures for Drilling, Tripping & Out of Hole

When a well influx occurs, rapid shut-in is the single most critical defense against a catastrophic blowout. Every second of delay permits additional formation fluid to enter the wellbore, enlarging total pit gain, elevating shut-in casing pressure ($SICP$), and increasing mechanical stress on the exposed formation and casing shoe.

Every rig must have written, rehearsed shut-in procedures for drilling, tripping and out-of-hole operations. The IWCF Level 2 syllabus asks candidates to explain the hard shut-in for drilling and tripping, to identify the manifold line-ups that make it possible, and to explain the responsibilities of the Driller and the crew.

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The Operational Debate: Hard Shut-In vs. Soft Shut-In

Industry practice historically debated the relative merits of "Hard Shut-In" versus "Soft Shut-In." Understanding this evolution explains why the hard shut-in is now the widely used method.

Definitions of Shut-In Methods

• Hard Shut-In: During normal drilling the choke-line HCR valve and the adjustable choke are closed, with a flow path through the choke manifold lined up to the mud-gas separator. When a kick is detected, the BOP (annular preventer or upper pipe ram) is closed immediately against the closed choke line. After the BOP is sealed, the choke line hydraulic fail-safe valve (HCR) is opened to align casing pressure to remote console gauges.
• Soft Shut-In: During drilling the choke-line valve (HCR) is closed but the choke is left open. When a kick occurs, the HCR is opened, the BOP is closed so that the well flows through the open choke, and the choke is then closed to shut in the well.

Why the Hard Shut-In Is Preferred

Soft shut-in was originally advocated due to fears that closing a BOP rapidly against flowing mud would induce destructive hydraulic shock waves, known as water hammer, capable of rupturing casing or wellhead equipment.

Field experience and published studies have shown this concern to be small in practice:

1. Drilling mud is compressible enough (it contains solids and often small amounts of gas) to cushion the pressure wave.
2. BOPs do not close instantaneously. API Standard 53 allows a surface ram BOP up to 30 seconds to close, and an annular preventer up to 30 seconds (below 18-3/4 in bore) or 45 seconds (18-3/4 in and larger), so the flow is not stopped abruptly.
3. The extra influx taken during a soft shut-in is a far greater risk to the casing shoe than the small surge from a hard shut-in.

Conversely, soft shut-in delays well closure, allowing additional volumes of formation fluid to enter the well. A larger gas influx creates a taller annular bubble height, reducing annular hydrostatic head and driving $SICP$ to dangerous levels that risk fracturing the casing shoe.

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Line-Ups Before Drilling and Tripping

A hard shut-in only works if the manifolds are already lined up correctly. Level 2 candidates must be able to identify simple line-ups from a diagram:

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Standardized Shut-In Procedure While Drilling

When a positive kick indicator is recognized while rotary or top-drive drilling, the Driller must execute the following sequence immediately:

1. Stop Rotary Table or Top Drive: Cease drill string rotation to protect equipment and eliminate mechanical agitation.
2. Pick Up Off Bottom & Space Out: Raise the traveling block until the nearest tool joint is spaced out safely above the BOP stack ram cavities and annular packing element.
3. Stop Mud Pumps: Disengage mud pumps to isolate circulating friction from hydrostatic pressure.
4. Close Designated BOP: Actuate the annular preventer (or upper pipe ram) to seal the annulus.
5. Open Choke Line HCR Valve: Open the hydraulic fail-safe valve against the closed remote choke to direct wellbore pressure to choke console transmitters.
6. Confirm Well is Fully Shut In: Inspect flowline to verify zero flow.
7. Notify Supervisors: Inform the Toolpusher, Rig Superintendent, and Company Representative.
8. Record Stabilized Pressures: Monitor and log stabilized $SIDPP$, $SICP$, and active pit volume gain.

A positive kick indicator is not checked again before closing the BOP (Section 4.1). Only a warning sign calls for a flow check first (Section 4.2).

Tool Joint Space-Out Management

Before closing any preventer, the Driller must ensure tool joints are not positioned across ram cavities. Closing a pipe ram across a heavy tool joint prevents ram closure, damages ram elastomer seals, bends the drill pipe, and causes catastrophic seal failure. Rigs utilize physical space-out marks or laser position sensors on the mast to guide the Driller.

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Standardized Shut-In Procedure While Tripping Pipe

Many kicks are taken while tripping, through swabbing and failure to keep the hole full. When a kick occurs during tripping, the crew must execute the tripping shut-in protocol:

1. Set Drill Pipe in Slips: Position the nearest tool joint at an ergonomic working height above the rotary table.
2. Stab Full Opening Safety Valve (FOSV / TIW Valve) in OPEN Position: The FOSV must be stabbed open to allow fluid flow through its bore without hydraulic resistance.
3. Close the FOSV: Turn the ball valve 90° with the operating wrench to seal the drill pipe bore.
4. Close Designated BOP: Actuate the annular preventer or pipe rams to seal the annulus.
5. Open Choke Line HCR Valve: Line up pressure to the closed remote choke.
6. Install Inside BOP (IBOP / Gray Valve) when directed: Make up the spring-loaded non-return valve on top of the closed FOSV.
7. Re-Open the FOSV: Opening the FOSV allows drill pipe pressure to transmit to surface gauges while the IBOP prevents upward flow.
8. Confirm Shut-In & Record Data: Verify zero flow, notify supervisors, and log stabilized pressures and pit gain.

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Standardized Shut-In Procedure When Out of Hole

If the well begins flowing when drill pipe is completely out of the hole:

1. Close Blind Rams or Blind Shear Rams Immediately: Actuate the blind rams from the rig floor console to establish a heavy-duty metal-to-rubber seal across the open hole diameter.
2. Open Choke Line HCR Valve: Route pressure to the closed remote choke gauge.
3. Confirm Shut-In: Verify flowline returns have ceased completely.
4. Notify Supervisors & Monitor Pressure: Record casing pressure buildup. Because no drill string is present, $SIDPP$ is absent; the well is controlled by volumetric methods and lubrication, by bullheading, or by stripping pipe back into the well, as the supervisor directs.

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Responsibilities of the Driller and the Crew

• Driller: detects or is told about the kick, carries out the shut-in, has authority to shut in without asking permission, and informs the toolpusher and company representative.
• Floor crew (roughnecks, assistant driller): stab and close the safety valve when tripping, check the flowline for flow after shut-in, and stand by for instructions.
• Derrickman and pit crew: watch pit and trip-tank levels, report changes immediately, and prepare to mix kill mud.
• Mud logger and other service crews: report gains, flow changes, drilling breaks and gas trends to the Driller and keep recording data.
• Everyone: report anything abnormal to the Driller at once and go to assigned positions; a shut-in well is never left unmonitored.

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Driller's Autonomous Shut-In Authority

Modern safety culture establishes the Driller's Absolute Shut-In Authority:

• The Driller has full authority to shut in the well immediately upon detecting any kick indicator or ambiguous flow anomaly.
• No Supervisory Approval Required: The Driller must never delay shut-in to seek managerial concurrence. Delayed shut-in has been a primary root cause of landmark blowout disasters.
• Safety Over NPT: If the Driller shuts in on a suspected influx and the well proves static, the Driller is commended for proactive barrier vigilance rather than criticized for non-productive time.