8.2 Annular Blowout Preventers

Mounted atop the BOP stack, the annular preventer is usually the first preventer closed when a kick is detected. While ram preventers require specific pipe dimensions to seal, the annular preventer's elastomeric packing element conforms to virtually any wellbore shape or diameter, making it the primary tool to shut in a well during drilling, tripping, or casing operations.

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Operating Principles and Hydraulic Mechanics

An annular preventer consists of a forged steel body, a removable head bowl, a vertical hydraulic piston, and a donut-shaped elastomeric packing element reinforced with high-strength alloy steel ribs.

Mechanical Closure Mechanics

Annular preventers use an upward-acting hydraulic piston to displace the packing element radially inward. Manufacturers use different housing geometries, for example a conical piston bowl or a spherical head, but all work the same way: closing pressure drives the piston, and the piston squeezes the packing element inward around whatever is in the bore.

In all designs, internal steel ribs guide elastomer inward during closing and pivot together to form a solid steel anti-extrusion barrier, preventing wellbore pressure from extruding rubber through the preventer top.

Opening Cycle

Porting hydraulic fluid into the opening chamber drives the piston downward. The natural elasticity of the rubber element causes it to expand radially outward, returning to its fully retracted position flush with the wellbore drift.

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Universal Sealing Capability & Operational Boundaries

The principal operational advantage of the annular preventer is its versatility across diverse tubular geometries:

• Drill Pipe & Upsets: Seals across standard pipe bodies, heavy-weight drill pipe, and tool joint tapers.
• Drill Collars & Casing: Packs off around large-diameter collars, casing, and tubing.
• Non-Cylindrical Objects: Seals on square/hexagonal kellys, wireline, and coiled tubing.

Emergency Complete Shut-Off (CSO)

When drill pipe is out of the hole and blind rams fail, an annular preventer can close on open hole (complete shut-off). However, closing an annular on open hole forces the rubber element to compress entirely into the wellbore center, inducing severe tensile stress, extreme distortion, and accelerated fatigue.

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Pressure Limitations Compared with Rams

The IWCF syllabus asks candidates to explain the annular's pressure limitations compared with rams:

• An annular preventer is often rated to a lower working pressure than the ram preventers in the same stack (for example a 5,000 psi annular on a 10,000 psi ram stack), and API Standard 53 tests it to only 70% of its rated working pressure.
• Its rubber element seals by being squeezed rather than by steel ram blocks, so it is more prone to wear, extrusion and leaks at high pressure, particularly while stripping or when closed on open hole.
• It cannot be mechanically locked like a ram and cannot hang off the weight of the drill string.

For these reasons the annular is often closed first because it fits anything, but when high shut-in pressures are expected or the shut-in will be long, the well is usually transferred to a pipe ram.

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Packing Element Elastomers & Mud Compatibility

Manufacturers produce packing elements in different elastomer compounds, identified by manufacturer markings and colour bands. One widely used scheme is shown below; check the manufacturer's data for the element actually installed:

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Operating Pressure Regulation

Unlike ram preventers operating at fixed 1,500 psi manifold pressure, annular preventers operate via an independent variable hydraulic pressure regulator controlled from the driller's console and remote panel.

Regulating Closing Pressure

Closing pressure is set from the manufacturer's chart for the pipe size and well pressure, commonly within 500 to 1,500 psi on a 3,000 psi control system:

• Closing on Drill Pipe: Pressure is set to achieve a leak-tight seal against the expected shut-in casing pressure (SICP).
• Excessive Pressure: Pressure exceeding manufacturer recommendations (e.g., 1,500 psi on small pipe) causes extreme rubber compression, accelerated wear, and severe tearing if pipe moves.
• Insufficient Pressure: Too low closing pressure allows wellbore fluid to channel past the rubber, causing fluid cutting and washouts.
• Wellbore Pressure Assist: In some annular designs, wellbore pressure acts upward beneath the piston, assisting closure and allowing hydraulic pressure to be reduced as well pressure rises.

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Stripping Operations Through the Annular Preventer

Stripping is running or pulling drill pipe into or out of a shut-in well under pressure. Because tool joint upsets have a larger diameter than the pipe body (e.g., $6\frac{1}{2}\text{ in}$ tool joint on $5\text{ in}$ pipe), passing a tool joint through a closed preventer presents severe friction and mechanical stress.

Operational Stripping Protocol

1. Reduce Hydraulic Closing Pressure: The driller decreases annular regulator pressure to the minimum pressure that prevents wellbore fluid leakage (from the manufacturer's stripping chart), allowing the elastomer element to flex smoothly over passing tool joint tapers.
2. Apply External Lubrication: Clean drilling fluid, water, or pipe lubricants are continuously applied to the drill string above the annular to cool the packing element and minimize friction.
3. Controlled Tripping Speed: Pipe movement must remain slow and steady, especially as each tool joint passes. Rapid entry slams tool joint shoulders into the packing element, tearing the rubber.
4. Tool Joint Taper: Drill pipe with $18^\circ$ bottleneck tool joint tapers strips far smoother than older $90^\circ$ square-shouldered connections.

Role of the Surge Accumulator Bottle

When a larger-diameter tool joint enters the closed annular bore, it displaces rubber, forcing the piston downward and expelling hydraulic fluid from the closing chamber. Without surge relief, a destructive hydraulic pressure spike occurs, forcing the element into extreme compression against the tool joint and causing severe rubber tearing or blown hydraulic lines.

A dedicated surge accumulator bottle (precharged with nitrogen to a pressure set by the manufacturer) connects into the annular closing line:

• Displaced fluid rushes into the surge bottle, compressing the nitrogen gas cushion and dampening the pressure spike.
• As the tool joint clears, the compressed nitrogen cushion expands, forcing hydraulic fluid back to maintain an unbroken seal around the drill pipe body.