blowout types, exploration and development shallow gas and “deep” drilling blowouts drill collars through the BOP, the blind-shear ram or pipe ram preventers cannot be used. .. as for instance new bonnet seals for the Cameron HQ preventers, and improved design of DBF” for a dBase file or File type “*. DB” for a. File Type, image/jpeg BOP: /8 PSI SHAEFFER ANNULAR AND /8 PSI CAMERON DOUBLE, /8 SINGLE RAM. An Innovative Ultradeepwater Subsea Blowout Preventer (SSBOP) Control System Using Shape Memory Alloy Actuators. Song, Gangbing (University of.
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They are usually installed in stacks of other valves. Blowout preventers were developed to cope 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 blowout. In addition to controlling the downhole occurring in the drilled hole pressure and the flow of oil and gas, blowout preventers are intended to prevent tubing e.
Blowout 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 blowout preventers are intended to provide fail-safety to the systems that include them. The abbreviated term preventerusually rzm by a type e.
A blowout preventer may also simply be referred to by its type e. The terms blowout preventerblowout preventer stack and blowout preventer system are commonly used interchangeably and in a general manner to describe cameroj assembly of several stacked blowout preventers of varying type and function, as well as auxiliary components.
A typical subsea deepwater blowout preventer system includes components such as electrical and hydraulic linescontrol pods, hydraulic accumulators, test valve, kill and choke lines and valves, riser jointhydraulic connectors, and a support frame.
Two categories of blowout preventer are most prevalent: A related valve, called an inside blowout preventerinternal blowout preventeror IBOPis positioned within, and restricts flow up, the drillpipe. This article does not address inside blowout preventer use. Blowout preventers are used on land wells, offshore rigs, and subsea wells. 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 filety;e 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. Unfortunately, blowout preventers do not always function correctly. Blowout preventers come in a variety of styles, sizes and pressure ratings. Several individual units serving various functions czmeron combined to compose a blowout preventer stack. Multiple blowout preventers of the same type are frequently provided for redundancyan important factor in the effectiveness of fail-safe devices.
In drilling a typical high-pressure well, drill strings are routed through a blowout 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, annulusbetween 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 blowout preventer units, sealing the annulus to stop the flow of fluids out of the wellbore.
Denser mud is then circulated vop 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 downhole pressure is overcome.
If the integrity of the well cameon 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 typw 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 blowout preventers and mud do not restrict the upward pressures of a kick, a blowout results, potentially shooting tubing, oil and gas up the wellbore, damaging the rig, and leaving well integrity in question. Since BOPs are important filetypee the safety of the crew and natural environment, as rwm as fletype 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 fileetype for as long as a cwmeron in extreme conditions [ citation needed ]. As a result, BOP assemblies have grown larger and heavier e. Thus a key focus in bpo technological development of BOPs over the last two decades has been limiting their footprint and weight while simultaneously increasing safe operating capacity.
BOPs come in two basic types, ram and annular. Cameron inand was brought to market in by Cameron Iron Works. A ram-type BOP is similar in operation to a gate valvebut uses a pair of opposing steel plungers, rams. The rams extend toward the center of the wellbore to restrict flow or filetypw open in order to permit flow.
The inner and top faces of the rams are fitted with packers elastomeric seals that press against each other, against the wellbore, and around tubing running through the wellbore. Outlets at the sides of the BOP housing body are used for connection to choke and kill lines or valves. Rams, or ram blocks, typw of four common types: Pipe rams close around a drill pipe, restricting flow in the annulus ring-shaped space between concentric objects between the outside of the drill pipe and the wellbore, but do not obstruct flow within the drill pipe.
Variable-bore pipe rams can accommodate tubing in a wider range of outside diameters than standard pipe rams, but typically with some loss of pressure capacity and longevity. Pipe ram should not be closed if there is no pipe in the hole. Blind rams also known xameron sealing ramswhich have no openings for tubing, can close off the well when the well does not contain a drill string or other tubing, and seal it. Shear rams are designed to shear the pipe in the well and seal the wellbore simultaneously.
It has steel blades to shear the pipe and seals to seal the annulus after ffiletype the pipe. Blind shear rams also known as shear seal rams, or sealing shear rams are tiletype to seal a wellbore, even when the bore is occupied by a drill string, by cutting through the drill string as the rams close off the well.
In addition to the standard ram functions, variable-bore pipe rams are frequently used as test rams in a modified blowout preventer device known as a stack test valve. Stack test valves are positioned at the bottom of a BOP stack and resist downward pressure unlike BOPs, which resist upward pressures. By closing the test ram and a BOP ram about the drillstring and pressurizing the annulus, the BOP is pressure-tested for proper function.
The original ram BOPs of the s were simple and rugged manual tam with minimal parts. The BOP housing body had a vertical well bore and horizontal ram cavity ram guide chamber. Opposing rams plungers in the ram cavity translated horizontally, actuated by threaded ram shafts piston rods in the manner of a screw dameron.
Torque from turning the ram shafts by wrench or hand wheel was converted to linear motion and the rams, coupled to the inner ends of the ram shafts, opened and closed the well bore.
Such screw jack type operation provided enough mechanical advantage for rams to overcome downhole pressures and seal the wellbore annulus. Hydraulic rams BOPs were in use by the s. Hydraulically actuated blowout preventers had many potential advantages. The pressure could be equalized in the opposing hydraulic cylinders causing the rams to operate in unison. Relatively rapid actuation and remote control were facilitated, and hydraulic rams were well-suited to high pressure wells.
Because BOPs are depended on for safety and reliability, efforts to minimize the complexity of the devices are still employed to ensure longevity. As a result, despite the ever-increasing demands placed on them, state of the art ram BOPs are conceptually the same as the first effective models, and resemble those units in many ways.
Ram BOPs for use in deepwater applications universally employ hydraulic actuation. Threaded shafts are often still incorporated into hydraulic ram BOPs as lock rods that hold the ram in position after hydraulic actuation.
By using a mechanical ram locking mechanism, constant hydraulic pressure need not be maintained. Lock rods may be coupled to ram shafts or not, depending on manufacturer. Other types of ram locks, such as wedge locks, are also used.
Cameron ram-type blowout preventer – Wikipedia
Typical ram actuator assemblies operator systems are secured to the BOP housing by removable bonnets. Unbolting the bonnets from the housing allows BOP maintenance and facilitates the substitution of rams.
Shear-type ram BOPs require the greatest closing force in order to cut through tubing occupying the wellbore. Ram BOPs are typically designed so that well pressure will help maintain the rams in their closed, sealing position.
Providing a channel in the ram also limits the thrust required to overcome well bore pressure. Single ram and double ram BOPs are commonly available. The names refer to the quantity of ram cavities equivalent to the effective quantity of valves contained in the unit.
A double ram BOP is more compact and lighter than a stack of two single ram BOPs while providing the same functionality, and is thus desirable in many applications. Triple ram BOPs are also manufactured, but not typ common. Technological development of ram BOPs has been directed towards deeper and higher pressure wells, greater reliability, reduced maintenance, facilitated replacement of components, facilitated ROV intervention, reduced dameron fluid consumption, and improved connectors, packers, seals, locks and rams.
In addition, limiting BOP weight and footprint are significant concerns to account for the limitations of existing rigs. The annular blowout preventer was invented by Granville Sloan Knox camerron ; a U. An annular-type blowout preventer can close around the drill string, casing or a non-cylindrical object, such as the kelly.
Drill pipe including the larger-diameter tool joints threaded connectors can be “stripped” i. Annular blowout preventers are also effective at maintaining a seal around the drillpipe even as it rotates during drilling. Regulations typically require that an annular preventer be able to completely close a wellbore, but annular preventers are generally not as effective as ram preventers in maintaining a seal on an open hole.
Annular BOPs are typically located at the viletype of a BOP stack, with one or two annular preventers positioned above a series of several ram preventers. An annular blowout preventer uses the principle of a wedge to shut in the wellbore.
It has a donut-like rubber seal, known as an elastomeric packing unit, reinforced with steel ribs. The packing unit is situated in the BOP housing between the head and hydraulic piston. When the piston is actuated, its upward thrust forces the packing unit to constrict, like a sphinctersealing the annulus or openhole. Annular preventers have only two moving parts, piston and packing unit, making them simple and easy to maintain relative to ram preventers.
As the piston rises, vertical movement of the packing unit is restricted by the head and the sloped face of the piston squeezes the packing unit inward, toward the center of the wellbore.
InAdo N. Vujasinovic was awarded a giletype for a variation on the annular preventer known as a spherical blowout preventer, so-named because of its spherical-faced head. Both types of annular preventer are in common use. When wells are drilled on land or in very shallow water where the wellhead is above the water line, BOPs are activated by hydraulic pressure from a remote accumulator.
Several control stations will be mounted around the rig.
They also can be closed manually by turning large wheel-like handles. In deeper offshore operations with the wellhead just above the mudline on the sea floor, there are five primary ways by which a BOP can be controlled.
The possible means are: