9.2 Internal Blowout Preventers & Auxiliary Equipment

Blowout Preventer (BOP) stacks seal the annular space between casing and drill string. However, the drill string forms an open conduit connecting downhole formations directly to the rig floor. If an influx enters the drill pipe through bit nozzles, annular preventers cannot arrest internal flow. To protect the rig floor, maintain wellbore containment, and safely process gas-cut mud at surface, drilling operations depend on internal well control barrier valves and surface mud-gas processing equipment.

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1. Kelly Cocks (Upper and Lower)

Kelly cocks isolate surface circulating equipment from internal drill string pressures.

Upper Kelly Cock

Installed between the rotary swivel and top of the kelly with left-hand threads to resist backing off under clockwise table torque. Rated equal to or exceeding BOP stack pressure, closing it protects the flexible rotary hose, swivel washpipe, and standpipe manifold from extreme well pressure.

Lower Kelly Cock (Lower Kelly Valve)

Installed between the bottom of the kelly and the saver sub with standard right-hand threads. It prevents drilling fluid inside the kelly from spilling onto the floor during connections, and provides an emergency barrier if a kick flows up the string.

Top-Drive IBOP Valves

On top-drive rigs the kelly cocks are replaced by two valves in the top drive: an upper valve that is remotely (hydraulically) operated from the driller's console and a lower valve that is operated manually. Closing them isolates the top drive, rotary hose and standpipe from well pressure.

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2. Full Opening Safety Valve (FOSV / TIW Valve)

The Full Opening Safety Valve (FOSV)—commonly termed a TIW valve—is a quarter-turn spherical ball valve designed for emergency stabbing into the drill string during tripping.

Design & Readiness Mandate

In the open position, the FOSV provides an unobstructed bore matching the inside diameter of drill pipe tool joints, allowing wireline logging sondes, free-point tools, or drop-in darts to pass downhole unimpeded. During tripping, the FOSV must remain on the rig floor in the FULLY OPEN position, equipped with threads matching the tubulars in the hole (or made up with a crossover sub), with its dedicated operating wrench beside it.

Why the correct crossover matters: the safety valve must be stabbed onto whatever is at the rotary table (drill pipe, heavy-weight pipe, drill collars, casing or tubing), and these often have different connections. If the correct-size crossover is not made up to the valve and ready on the drill floor, the crew cannot close in the string quickly when a kick happens with a different tubular in the slips.

Tripping Deployment Protocol

1. Stab While Open: Stabbing the valve open allows upward-surging fluids to exit through the bore, minimizing upward jetting thrust that would otherwise push the valve off the pipe box.
2. Make Up & Close: Once stabbed and torqued using rig tongs, the valve is closed 90 degrees using its operating wrench to seal the internal bore.
3. Stack Closure: Only after the drill string is isolated by the closed FOSV are BOP annular or pipe rams closed.

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3. Inside Blowout Preventer (IBOP / Gray Valve)

The Inside Blowout Preventer (IBOP), or Gray valve, is a heavy-duty, spring-loaded non-return check valve (dart or plunger type).

Operation & Release Rod Tool

The internal spring drives an elastomer-faced dart against a tapered seat, stopping upward flow while allowing mud to be pumped downward. A threaded release rod holds the dart open against its spring during stabbing; once made up into the string, the release rod is unscrewed, allowing the dart to seal against backpressure. The internal mechanism obstructs the bore, preventing wireline tool passage.

Coordinated Staging: FOSV + IBOP

1. Step 1: Stab, make up, and close the FOSV to immediately halt well flow.
2. Step 2: Thread the IBOP directly on top of the closed FOSV.
3. Step 3: Reopen the FOSV. Pumping operations can now proceed downhole through the IBOP, which automatically prevents reverse flow.

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4. Drill Pipe Float Valves (Bit Floats)

Float valves are check valves installed in a float sub directly above the drill bit nozzles, preventing backflow of drilling mud, cuttings, and reservoir fluids into the bottom-hole assembly.

Plunger vs Flapper Floats

• Plunger Type: Spring-loaded axial piston delivering positive reverse shut-off, but permanently obstructs the bore (preventing wireline passage). Like all floats it stops the string self-filling when running in, so the string must be filled from surface at intervals.
• Flapper Type: Spring-assisted hinged flapper swinging flat against the sub wall during circulation, providing an unobstructed bore for wireline tools and drop-in balls. Vented flappers feature a micro-bleed orifice that equalizes pressure slowly, allowing static Shut-In Drill Pipe Pressure (SIDPP) to be read directly.

"Bumping the Float" Procedure

With an unvented float, the standpipe gauge reads 0 psi at shut-in. To determine true SIDPP:

1. Record static Shut-In Casing Pressure (SICP).
2. Start the mud pump at 2 to 5 SPM, slowly pumping fluid into the drill string while observing standpipe pressure.
3. At the instant pump pressure overcomes pressure below the bit, the float cracks open ("bumps"). Standpipe pressure levels off or breaks over, and casing pressure begins to tick upward.
4. Stop pumping as soon as casing pressure starts to rise. The drill pipe pressure at that point, less any rise in casing pressure above the original SICP, is the true SIDPP.

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5. Surface Mud Processing: Mud-Gas Separator (MGS)

The Mud-Gas Separator (MGS), or "poor boy" degasser, is a vertical vessel upstream of the shale shakers that separates free gas from gas-cut mud arriving from the choke manifold.

Separation Principles & Liquid Seal Leg

Gas-cut mud cascades over internal baffle plates that spread fluid into thin sheets, allowing free gas to break out rapidly by gravity and vent through an 8- to 12-inch derrick vent line. Degassed mud discharges through an inverted U-tube piping loop into the shaker ditch. The vertical height of this column ($h_{\text{seal}}$) provides hydrostatic backpressure that prevents gas from entering the shaker house.

Gas Blow-Through Pressure Limit

The maximum allowable vessel backpressure before gas blows through the liquid seal is:

$P_{\text{blow-through}} = 0.052 \times \rho_{\text{mud}} \times h_{\text{seal}}\quad [\text{psi}]$

In metric units: $P_{\text{blow-through}} = \frac{\rho_{\text{mud}} \times g \times h_{\text{seal}}}{100}\text{ bar}$.

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6. Vacuum Degassers

Installed downstream of the shale shakers, the vacuum degasser extracts microscopic entrained gas bubbles and dissolved gas that gravity segregation cannot remove.

• Vacuum Mechanism: A vacuum pump or liquid-jet eductor maintains a sub-atmospheric vacuum of $5\text{ to }10\text{ inHg}$ ($0.17 - 0.34\text{ bar}$ below atmosphere) inside the vessel.
• Boyle's Law Expansion: Mud spreads across corrugated internal plates. Negative pressure causes microscopic gas bubbles to expand ($P_1 V_1 = P_2 V_2$), burst, and vent away safely.
• Preventing Pump Cavitation: Removing entrained gas restores true mud density and prevents vapor-locking and severe impeller cavitation in centrifugal charging pumps and triplex mud pumps.