The Defining Series: Blowout Preventers

Before the development of blowout preventers, operators allowed pressured fluids to flow uncontrolled from formations to the surface and into the atmosphere. Only after the pressure supporting these blowouts abated and surface pressures fell to a manageable level were rig workers able to cap the well. Blowouts were dangerous for the crew, threatened the well-being of the surrounding environment, damaged drilling equipment, wasted resources and caused irreparable harm to the producing zone.

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In , Harry Cameron and Jim Abercrombie designed and manufactured the first blowout preventers (BOPs). Assemblies of valves and other devices installed atop a wellhead during drilling operations are called BOP stacks; they provide a means by which rig crews are able to contain unexpected flow and high pressures. They allow crews to manage these influxes by injecting dense fluids down the well, which stop, or kill, the flow of formation fluids; this kill operation is accomplished while preventing well fluids from being released into the atmosphere.

Within the E&P industry, the terms blowout preventer, BOP stack and blowout preventer system are used interchangeably. During drilling and completion operations, they are the second barrier to formation flow; hydrostatic pressure at the formation created by a column of drilling fluid and zonal isolation provided by casing and cement constitute the primary barrier.

The individual BOPs that constitute a system are stacked vertically atop the well. They are aligned to allow access through them into the wellbore while their various functions provide a variety of methods for sealing the well during drilling, completion or intervention operations. They are sized to fit the internal diameter of the wellhead and expected surface pressures.

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Blowout preventer stacks typically include annular BOPs and ram-type BOPs. Annular BOPs were introduced to the industry in by Granville Sloan Knox. These devices force circular steel-reinforced rubber elements to close on and create a seal around drillpipe or other tools that may be in the wellbore at the time of shut-in (Figure 1). When annular BOPs are shut in around a pipe, the pipe may be moved up or down or rotated without breaking the seal. Designed to prevent flow up the casing-drillpipe annulus, annular BOPs are also able to seal a clear wellbore in which no obstruction is present although doing so reduces the rated working pressure of the sealing element by 50%.

Ram-type BOPs include rubber-faced steel rams that are brought together to create a seal or, like annular BOPs, form a seal around a tool in the wellhead (Figure 2). Shear rams are high-strength hydraulically powered rams that are able to sever drillpipe. They include casing shear rams and blind shear rams. Both are designed to cut drillpipe or other obstructions in the well. Blind shear rams can completely seal the well. Casing shear rams, while not able to form a seal, typically are able to cut larger size tubulars than those that blind shear rams can cut.

Drillers use a control system to actuate rams that is comprised of accumulator bottles containing pressurized hydraulic fluid, a hydraulic fluid storage reservoir, a pumping system and hydraulic piping. The hydraulic fluid is directed to a desired function on the BOP stack via a remote control panel.

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