9.1 Annular Preventers: Design, Closing Ratios, Stripping Pressure & Element Selection

The annular blowout preventer is universally recognized as a versatile shut-in component of the secondary well-control system in both surface and subsea BOP stacks. Unlike ram-type preventers that require specific pipe diameters or open hole conditions, an annular preventer can close and seal securely around virtually any object in the wellbore—including hexagonal and square kellys, drillpipe, tool joints, heavyweight drillpipe, drill collars, casing, tubing, and wireline—as well as achieving a full shut-in on open hole in an emergency.

For drilling supervisors, superintendents, and wellsite engineers, understanding internal mechanical kinematics, elastomer compounding, hydraulic closing ratios, and pressure regulator dynamics of annular preventers is essential to maintaining well integrity during shut-in and high-risk stripping operations.

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Annular Preventer Anatomy and Operating Principles

An annular preventer consists of five primary structural components: the forged steel body/housing, a bolted or latched removable head/cover, a vertically traversing hydraulic operating piston, an opening chamber, a closing chamber, and a reinforced elastomeric packing unit.

               ┌─────────────────────────────────┐
               │       Removable BOP Head        │
               ├──────┬───────────────────┬──────┤
               │      │  Packing Element  │      │
               │      │ (Squeezed Inward) │      │
               │      └─────────▲─────────┘      │
               │     Closing    │    Closing     │
               │     Chamber    │    Chamber     │
               │        ▲       │       ▲        │
               │   ═════╪═══════╪═══════╪═════   │
               │   [ Hydraulic Operating Piston ]│
               │   ═══════════════════════════   │
               │        ▼               ▼        │
               │     Opening         Opening     │
               │     Chamber         Chamber     │
               └─────────────────────────────────┘

When hydraulic fluid from the accumulator closing unit is directed into the closing chamber, the operating piston is forced vertically upward. As the piston ascends, its contoured internal bowl pushes against the outer circumference of the doughnut-shaped packing unit. Because the removable head physically restricts vertical expansion of the elastomer, the upward thrust forces the resilient rubber inward toward the center of the wellbore bore.

Opening the preventer reverses the hydraulic path: closing pressure is vented to the accumulator reservoir while pressurized fluid is pumped into the opening chamber, driving the operating piston downward. The internal elastic memory of the molded elastomer, assisted by bonded spring-steel segments, forces the packing element back to its fully retracted, full-bore diameter.

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Packing Element Geometries: Spherical, Conical, Cylindrical, and Independent Piston

Annular designs convert hydraulic piston force into inward packing displacement, but their pressure-assist behaviour and operating curves differ. Use the actual sectional drawing to identify the piston, opening/closing chambers, packing and reinforcing inserts.

• Hydril GK: HMH describes a piston and packing unit as its two moving parts. Hydraulic motion drives elastomer/inserts inward, and wellbore pressure assists in maintaining closure. Its packing is available in compounds selected for the service.
• Cameron DL: SLB describes an operating piston and pusher plate displacing the elastomer inward. Interlocking inserts support the packer; the design does not require wellbore assist. Its quick-release top permits packer changeout.
• Other surface/subsea designs: Piston/packing geometry, control-fluid hydrostatic effects and compensation arrangements are model-specific. A brand name or a generic spherical/conical/cylindrical label does not provide an operating-pressure setting.

Reinforcing inserts support the elastomer against extrusion and help maintain the required bore/closure geometry. Identify their condition and the correct packing assembly from the installed equipment documentation.

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Elastomer Compounding and Selection Guidelines

Selecting the correct elastomer compound is a life-critical engineering decision. Elastomer failure during well control can lead to rapid seal blowout, structural fires, or uncontrolled hydrocarbon release. Packing unit elastomers are formulated from specific base polymers matched to drilling fluid chemistry and anticipated wellbore thermal profiles:

*Note: Color coding, identification bands, and operating temperature thresholds are manufacturer-specific guidelines rather than universal industry standards. For example, while red markings commonly denote Nitrile and green denote Neoprene among several major equipment manufacturers, color-striping schemes and exact compound ratings vary between vendors (such as SLB Cameron, Hydril/Baker Hughes, and NOV Shaffer). Rig personnel must consult manufacturer technical data sheets and rig-specific equipment files.

Storage and shelf-life protocols mandate that spare packing elements be stored in a cool, dark, dry warehouse away from electric motors (which generate ozone) and direct ultraviolet sunlight. Apply the manufacturer's storage, inspection and use/discard criteria before installation. A generic age range or inspection alone does not authorize use beyond an applicable expiry or rejection criterion.

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Hydraulic Closing Ratios and Wellbore Pressure Assist

Hydraulic closing force is operating pressure multiplied by the effective closing-piston area: $F_{\text{hyd,close}}=P_{\text{close}}A_{\text{close}}$ The net packing force also depends on the design's well-pressure forces, opposing hydraulic/hydrostatic forces and packing resistance. A single generic bore-area/closing-area ratio does not determine the required annular pressure. Use the manufacturer's initial and holding curves for the actual pipe/element and well pressure, including subsea control-fluid effects.

Wellbore Pressure Assist: Mechanism and Design Differences

Certain annular preventer designs—specifically spherical and tapered units such as the Hydril GK, Hydril MSP, and Shaffer spherical—utilize wellbore pressure to assist in maintaining a packoff seal around the pipe:

• In these designs, the geometry of the operating piston exposes its lower surface to wellbore fluid pressure.
• Once the packing element is hydraulically closed around the pipe and wellbore pressure accumulates below the element, that wellbore pressure acts upward against the bottom of the piston.
• This creates a self-energizing wellbore pressure assist: higher wellbore pressure generates an incremental upward thrust that supplements the hydraulic closing force to maintain packoff.

However, wellbore pressure assist is not universal:

• SLB Cameron DL Annular Preventer: The Cameron DL is engineered with a quick-release head and an independent closing piston geometry where wellbore pressure assist is NOT required for sealing. Sealing force is derived entirely from the hydraulic operating system displacing the piston against the element and housing geometry. Packoff does not rely on wellbore pressure communication beneath the piston.

Drilling supervisors must note this critical distinction:

Conversely, in certain cylindrical designs (such as deepwater subsea Hydril GL preventers), an auxiliary secondary chamber is plumbed to compensate for the hydrostatic head of marine riser mud, preventing unintentional hydraulic closure at great water depths.

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Hydraulic Regulator Operation & Stripping Pressure Management

During routine drilling operations, the annular preventer hydraulic circuit is supplied by an air- or electrically driven pressure regulating reducing valve located on the BOP control panel. The regulator drops the $3,000\text{ psi}$ accumulator manifold pressure down to the manufacturer-recommended standby setting—typically $800\text{ to }1,000\text{ psi}$ for a 13-5/8" $5,000\text{ psi}$ or $10,000\text{ psi}$ annular preventer.

Kinematics of Stripping Operations

When pipe must be stripped into or out of a shut-in well under pressure, tool joints (which have an outer diameter substantially larger than the drillpipe body) must physically pass through the closed elastomer packing element:

1. As a tool joint enters the packing unit, it forces the elastomer radially outward.
2. This outward expansion displaces the operating piston slightly downward.
3. The downward movement of the piston compresses the hydraulic fluid in the closing chamber, generating a severe, instantaneous hydraulic pressure spike.
4. Excessive closing pressure can prevent the packing from yielding adequately and damage it as a tool joint passes. Use the installed model’s approved stripping curve and control-fluid arrangement; there is no universal shut-in pressure or guaranteed damage threshold.

TOOL JOINT STRIPPING SEQUENCE:
[Tool Joint Approaches] --> [Displaces Rubber Outward] --> [Piston Pushed Down]
                                                                   │
                                                        [Hydraulic Surge Spike]
                                                                   │
                                                        [Surge Bottle Absorbs]
                                                                   │
[Regulator Vents Excess Fluid] <-- [Closing Pressure Adjusted per Guidelines]

The Hydraulic Surge Absorber (Surge Bottle)

Use the surge/control arrangement specified for the installed preventer and hydraulic circuit. It must accept displaced closing fluid without imposing damaging pressure on the packing. Bottle volume, precharge, location and any regulator-return arrangement are equipment-specific; a universal 10-gallon, 400–600 psi configuration cannot be assigned to every stack.

Operational Stripping Guidelines

Use the installed preventer's stripping curves, actual pipe/tool-joint geometry and approved operating procedure:

1. Set the minimum effective closing pressure required for the conditions; do not substitute a universal 400–800 psi range.
2. Verify the surge arrangement and monitor pressure and element condition as each joint passes.
3. Apply the approved lubrication/leakage policy. Some procedures permit a slight controlled weep; others require a maintained seal.
4. Control pipe speed and joint passage according to the rated equipment and well conditions. One joint/minute and 1–2 ft/s are not interchangeable universal speeds.