Blowout preventer

Cameron Int'l Corporation's EVO Ram BOP Drawing.

Hydril Annular BOP Drawing.

Blowout preventer

The blow-out preventer is a large, specialized valve used to seal, control & monitor oil and gas wells. Blow-out preventers were developed for coping with extreme erratic pressures and uncontrolled flow (formation kick) emanating from a well reservoir during drilling. Kicks can lead to a potentially catastrophic event known as a blow-out. In addition to controlling the down-hole (occurring in the drilled hole) pressure and the flow of oil and gas, blow-out preventers are intended to prevent tubing (e.g. drill pipe and well casing), tools and drilling fluid from being blown out of the wellbore (also known as bore hole, the hole leading to the reservoir) when a blow-out threatens. blow-out preventers are critical to the safety of crew, rig (the equipment system used to drill a wellbore) and environment, and to the monitoring and maintenance of well integrity; thus blow-out preventers are intended to be fail-safe devices.

That term BOP (an initialism rather than spoken as a word, i.e.- pronounced 'B' 'O' 'P') is used in oilfield vernacular to refer to blow-out preventers.

The abbreviated term preventer, usually prefaced by a type (e.g. ram preventer), is used to refer to a single blow-out preventer unit. A blow-out preventer may also simply be referred to by its type (e.g. ram).

The terms blow-out preventer, blow-out preventer stack and blow-out preventer system are commonly used interchangeably and in a general manner to describe an assembly of several stacked blow-out preventers of varying type and function, as well as auxiliary components. A typical subsea deepwater blow-out preventer system includes components such as electrical and hydraulic lines, control pods, hydraulic accumulators, test valve, kill and choke lines and valves, riser joint, hydraulic connectors, and a support frame.

Two categories of blow-out preventer are most prevalent: ram and annular. BOP stacks frequently utilize both types, typically with at least one annular BOP stacked above several ram BOPs.

(A related valve, called an inside blow-out preventer, internal blow-out preventer, or IBOP, is positioned within, and restricts flow up, the drillpipe. This article does not address inside blow-out preventer use.)

blow-out preventers are used at land and offshore rigs, and subsea. Land and subsea BOPs are secured to the top of the wellbore, known as the wellhead. BOPs on offshore rigs are mounted below the rig deck. Subsea BOPs are connected to the offshore rig above by a drilling riser that provides a continuous pathway for the drill string and fluids emanating from the wellbore. In effect, a riser extends the wellbore to the rig.

Use of blow-out preventer:-

The invention of blow-out preventers was instrumental in reducing the incidence of oil gushers, blow-outs, which are dangerous and costly.

blow-out preventers come in a variety of styles, sizes and pressure ratings. Several individual units serving various functions are combined to compose a blow-out preventer stack. Multiple blow-out preventers of the same type are frequently provided for redundancy, an important factor in the effectiveness of fail-safe devices.

The primary functions of a blow-out preventer system are to

Confine well fluid to the wellbore;

Provide means to add fluid to the wellbore;

Allow controlled volumes of fluid to be withdrawn from the wellbore.

Additionally, and in performing those primary functions, blow-out preventer systems are used to:

Regulate and monitor wellbore pressure;

Center and hang off the drill string in the wellbore;

Shut in the well (e.g. seal the void, annulus, between drillpipe and casing);

“Kill” the well (prevent the flow of formation fluid, influx, from the reservoir into the wellbore) ;

Seal the wellhead (close off the wellbore);

Sever the casing or drill pipe (in case of emergencies).

In drilling a typical high-pressure well, drill strings are routed through a blow-out preventer stack toward the reservoir of oil and gas. As the well is drilled, drilling fluid, “mud,” is fed through the drill string down to the drill bit, “blade,” and returns up the wellbore in the ring-shaped void, annulus, between the outside of the drill pipe and the casing (piping that lines the wellbore). The column of drilling mud exerts downward hydrostatic pressure to counter opposing pressure from the formation being drilled, allowing drilling to proceed.

When a kick (influx of formation fluid) occurs, rig operators or automatic systems close the blow-out preventer units, sealing the annulus to stop the flow of fluids out of the wellbore. Denser mud is then circulated into the wellbore down the drill string, up the annulus and out through the choke line at the base of the BOP stack through chokes (flow restrictors) until down-hole pressure is overcome. Once “kill weight” mud extends from the bottom of the well to the top, the well has been “killed”. If the integrity of the well is intact drilling may be resumed. Alternatively, if circulation is not feasible it may be possible to kill the well by "bullheading", forcibly pumping, in the heavier mud from the top through the kill line connection at the base of the stack. This is less desirable because of the higher surface pressures likely needed and the fact that much of the mud originally in the annulus must be forced into receptive formations in the open hole section beneath the deepest casing shoe.

If the blow-out preventers and mud do not restrict the upward pressures of a kick, a blow-out results, potentially shooting tubing, oil and gas up the wellbore, damaging the rig, and leaving well integrity in question.

Since BOPs are important for the safety of the crew and natural environment, as well as the drilling rig and the wellbore itself, authorities recommend, and regulations require, that BOPs be regularly inspected, tested and refurbished. Tests vary from daily test of functions on critical wells to monthly or less frequent testing on wells with low likelihood of control problems.

Exploitable reservoirs of oil and gas are increasingly rare and remote, leading to increased subsea deepwater well exploration and requiring BOPs to remain submerged for as long as a year in extreme conditions. As a result, BOP assemblies have grown larger and heavier (e.g. a single ram-type BOP unit can weigh in excess of 30,000 pounds), while the space allotted for BOP stacks on existing offshore rigs has not grown commensurately. Thus a key focus in the technological development of BOPs over the last two decades has been limiting their footprint and weight while simultaneously increasing safe operating capacity.