May. 06, 2024
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The Lucas Gusher at Spindletop, Texas (1901)A blowout is the uncontrolled release of crude oil and/or natural gas from an oil well or gas well after pressure control systems have failed.[1] Modern wells have blowout preventers intended to prevent such an occurrence. An accidental spark during a blowout can lead to a catastrophic oil or gas fire.
Prior to the advent of pressure control equipment in the 1920s, the uncontrolled release of oil and gas from a well while drilling was common and was known as an oil gusher, gusher or wild well.
History
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Gushers were an icon of oil exploration during the late 19th and early 20th centuries. During that era, the simple drilling techniques, such as cable-tool drilling, and the lack of blowout preventers meant that drillers could not control high-pressure reservoirs. When these high-pressure zones were breached, the oil or natural gas would travel up the well at a high rate, forcing out the drill string and creating a gusher. A well which began as a gusher was said to have "blown in": for instance, the Lakeview Gusher blew in in 1910. These uncapped wells could produce large amounts of oil, often shooting 200 feet (61 m) or higher into the air.[2] A blowout primarily composed of natural gas was known as a gas gusher.
Despite being symbols of new-found wealth, gushers were dangerous and wasteful. They killed workmen involved in drilling, destroyed equipment, and coated the landscape with thousands of barrels of oil; additionally, the explosive concussion released by the well when it pierces an oil/gas reservoir has been responsible for a number of oilmen losing their hearing entirely; standing too near to the drilling rig at the moment it drills into the oil reservoir is extremely hazardous. The impact on wildlife is very hard to quantify, but can only be estimated to be mild in the most optimistic models—realistically, the ecological impact is estimated by scientists across the ideological spectrum to be severe, profound, and lasting.[3]
To complicate matters further, the free flowing oil was—and is—in danger of igniting.[4] One dramatic account of a blowout and fire reads,
With a roar like a hundred express trains racing across the countryside, the well blew out, spewing oil in all directions. The derrick simply evaporated. Casings wilted like lettuce out of water, as heavy machinery writhed and twisted into grotesque shapes in the blazing inferno.[5]
The development of rotary drilling techniques where the density of the drilling fluid is sufficient to overcome the downhole pressure of a newly penetrated zone meant that gushers became avoidable. If however the fluid density was not adequate or fluids were lost to the formation, then there was still a significant risk of a well blowout.
In 1924 the first successful blowout preventer was brought to market.[6] The BOP valve affixed to the wellhead could be closed in the event of drilling into a high pressure zone, and the well fluids contained. Well control techniques could be used to regain control of the well. As the technology developed, blowout preventers became standard equipment, and gushers became a thing of the past.
In the modern petroleum industry, uncontrollable wells became known as blowouts and are comparatively rare. There has been significant improvement in technology, well control techniques, and personnel training which has helped to prevent their occurring.[1] From 1976 to 1981, 21 blowout reports are available.[1]
Notable gushers
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Cause of blowouts
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Reservoir pressure
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A petroleum trap. An irregularity (the trap) in a layer of impermeable rocks (the seal) retains upward-flowing petroleum, forming a reservoir.Petroleum or crude oil is a naturally occurring, flammable liquid consisting of a complex mixture of hydrocarbons of various molecular weights, and other organic compounds, found in geologic formations beneath the Earth's surface. Because most hydrocarbons are lighter than rock or water, they often migrate upward and occasionally laterally through adjacent rock layers until either reaching the surface or becoming trapped within porous rocks (known as reservoirs) by impermeable rocks above. When hydrocarbons are concentrated in a trap, an oil field forms, from which the liquid can be extracted by drilling and pumping. The downhole pressure in the rock structures changes depending upon the depth and the characteristics of the source rock. Natural gas (mostly methane) may be present also, usually above the oil within the reservoir, but sometimes dissolved in the oil at reservoir pressure and temperature. Dissolved gas typically comes out of solution as free gas as the pressure is reduced either under controlled production operations or in a kick, or in an uncontrolled blowout. The hydrocarbon in some reservoirs may be essentially all natural gas.
Formation kick
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The downhole fluid pressures are controlled in modern wells through the balancing of the hydrostatic pressure provided by the mud column. Should the balance of the drilling mud pressure be incorrect (i.e., the mud pressure gradient is less than the formation pore pressure gradient), then formation fluids (oil, natural gas, and/or water) can begin to flow into the wellbore and up the annulus (the space between the outside of the drill string and the wall of the open hole or the inside of the casing), and/or inside the drill pipe. This is commonly called a kick. Ideally, mechanical barriers such as blowout preventers (BOPs) can be closed to isolate the well while the hydrostatic balance is regained through circulation of fluids in the well. But if the well is not shut in (common term for the closing of the blow-out preventer), a kick can quickly escalate into a blowout when the formation fluids reach the surface, especially when the influx contains gas that expands rapidly with the reduced pressure as it flows up the wellbore, further decreasing the effective weight of the fluid.
Early warning signs of an impending well kick while drilling are:
Other warning signs during the drilling operation are:
The primary means of detecting a kick while drilling is a relative change in the circulation rate back up to the surface into the mud pits. The drilling crew or mud engineer keeps track of the level in the mud pits and closely monitors the rate of mud returns versus the rate that is being pumped down the drill pipe. Upon encountering a zone of higher pressure than is being exerted by the hydrostatic head of the drilling mud (including the small additional frictional head while circulating) at the bit, an increase in mud return rate would be noticed as the formation fluid influx blends in with the circulating drilling mud. Conversely, if the rate of returns is slower than expected, it means that a certain amount of the mud is being lost to a thief zone somewhere below the last casing shoe. This does not necessarily result in a kick (and may never become one); however, a drop in the mud level might allow influx of formation fluids from other zones if the hydrostatic head is reduced to less than that of a full column of mud.[citation needed]
Well control
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The first response to detecting a kick would be to isolate the wellbore from the surface by activating the blow-out preventers and closing in the well. Then the drilling crew would attempt to circulate in a heavier kill fluid to increase the hydrostatic pressure (sometimes with the assistance of a well control company). In the process, the influx fluids will be slowly circulated out in a controlled manner, taking care not to allow any gas to accelerate up the wellbore too quickly by controlling casing pressure with chokes on a predetermined schedule.
This effect will be minor if the influx fluid is mainly salt water. And with an oil-based drilling fluid it can be masked in the early stages of controlling a kick because gas influx may dissolve into the oil under pressure at depth, only to come out of solution and expand rather rapidly as the influx nears the surface. Once all the contaminant has been circulated out, the shut-in casing pressure should have reached zero.[citation needed]
Capping stacks are used for controlling blowouts. The cap is an open valve that is closed after bolted on.[23]
Types of blowouts
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Ixtoc I oil well blowoutWell blowouts can occur during the drilling phase, during well testing, during well completion, during production, or during workover activities.[1]
Surface blowouts
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Blowouts can eject the drill string out of the well, and the force of the escaping fluid can be strong enough to damage the drilling rig. In addition to oil, the output of a well blowout might include natural gas, water, drilling fluid, mud, sand, rocks, and other substances.
Blowouts will often be ignited from sparks from rocks being ejected, or simply from heat generated by friction. A well control company then will need to extinguish the well fire or cap the well, and replace the casing head and other surface equipment. If the flowing gas contains poisonous hydrogen sulfide, the oil operator might decide to ignite the stream to convert this to less hazardous substances.[citation needed]
Sometimes blowouts can be so forceful that they cannot be directly brought under control from the surface, particularly if there is so much energy in the flowing zone that it does not deplete significantly over time. In such cases, other wells (called relief wells) may be drilled to intersect the well or pocket, in order to allow kill-weight fluids to be introduced at depth. When first drilled in the 1930s relief wells were drilled to inject water into the main drill well hole.[24] Contrary to what might be inferred from the term, such wells generally are not used to help relieve pressure using multiple outlets from the blowout zone.
Subsea blowouts
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The two main causes of a subsea blowout are equipment failures and imbalances with encountered subsurface reservoir pressure.[25] Subsea wells have pressure control equipment located on the seabed or between the riser pipe and drilling platform. Blowout preventers (BOPs) are the primary safety devices designed to maintain control of geologically driven well pressures. They contain hydraulic-powered cut-off mechanisms to stop the flow of hydrocarbons in the event of a loss of well control.[26]
Even with blowout prevention equipment and processes in place, operators must be prepared to respond to a blowout should one occur. Before drilling a well, a detailed well construction design plan, an Oil Spill Response Plan as well as a Well Containment Plan must be submitted, reviewed and approved by BSEE and is contingent upon access to adequate well containment resources in accordance to NTL 2010-N10.[27]
The Deepwater Horizon well blowout in the Gulf of Mexico in April 2010 occurred at a 5,000 feet (1,500 m) water depth.[28] Current blowout response capabilities in the U.S. Gulf of Mexico meet capture and process rates of 130,000 barrels of fluid per day and a gas handling capacity of 220 million cubic feet per day at depths through 10,000 feet.[29]
Underground blowouts
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An underground blowout is a special situation where fluids from high pressure zones flow uncontrolled to lower pressure zones within the wellbore. Usually this is from deeper higher pressure zones to shallower lower pressure formations. There may be no escaping fluid flow at the wellhead. However, the formation(s) receiving the influx can become overpressured, a possibility that future drilling plans in the vicinity must consider.[citation needed]
Blowout control companies
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Myron M. Kinley was a pioneer in fighting oil well fires and blowouts. He developed many patents and designs for the tools and techniques of oil firefighting. His father, Karl T. Kinley, attempted to extinguish an oil well fire with the help of a massive explosion—a method still in common use for fighting oil fires. Myron and Karl Kinley first successfully used explosives to extinguish an oil well fire in 1913.[30] Kinley would later form the M. M. Kinley Company in 1923.[30] Asger "Boots" Hansen and Edward Owen "Coots" Matthews also begin their careers under Kinley.
Paul N. "Red" Adair joined the M. M. Kinley Company in 1946, and worked 14 years with Myron Kinley before starting his own company, Red Adair Co., Inc., in 1959.
Red Adair Co. has helped in controlling offshore blowouts, including:
The 1968 American film, Hellfighters, which starred John Wayne, is about a group of oil well firefighters, based loosely on Adair's life; Adair, Hansen, and Matthews served as technical advisors on the film.
In 1994, Adair retired and sold his company to Global Industries. Management of Adair's company left and created International Well Control (IWC). In 1997, they would buy the company Boots & Coots International Well Control, Inc., which was founded by Hansen and Matthews in 1978.
Methods of quenching blowouts
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Subsea Well Containment
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Government Accountability Office diagram showing subsea well containment operationsAfter the Macondo-1 blowout on the Deepwater Horizon, the offshore industry collaborated with government regulators to develop a framework to respond to future subsea incidents. As a result, all energy companies operating in the deep-water U.S. Gulf of Mexico must submit an OPA 90 required Oil Spill Response Plan with the addition of a Regional Containment Demonstration Plan prior to any drilling activity.[32] In the event of a subsea blowout, these plans are immediately activated, drawing on some of the equipment and processes effectively used to contain the Deepwater Horizon well as others that have been developed in its aftermath.
In order to regain control of a subsea well, the Responsible Party would first secure the safety of all personnel on board the rig and then begin a detailed evaluation of the incident site. Remotely operated underwater vehicles (ROVs) would be dispatched to inspect the condition of the wellhead, Blowout Preventer (BOP) and other subsea well equipment. The debris removal process would begin immediately to provide clear access for a capping stack.
Once lowered and latched on the wellhead, a capping stack uses stored hydraulic pressure to close a hydraulic ram and stop the flow of hydrocarbons.[33] If shutting in the well could introduce unstable geological conditions in the wellbore, a cap and flow procedure would be used to contain hydrocarbons and safely transport them to a surface vessel.[34]
The Responsible Party works in collaboration with BSEE and the United States Coast Guard to oversee response efforts, including source control, recovering discharged oil and mitigating environmental impact.[35]
Several not-for-profit organizations provide a solution to effectively contain a subsea blowout. HWCG LLC and Marine Well Containment Company operate within the U.S. Gulf of Mexico[36] waters, while cooperatives like Oil Spill Response Limited offer support for international operations.
Use of nuclear explosions
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On Sep. 30, 1966, the Soviet Union experienced blowouts on five natural gas wells in Urta-Bulak, an area about 80 kilometers from Bukhara, Uzbekistan. It was claimed in Komsomoloskaya Pravda that after years of burning uncontrollably they were able to stop them entirely.[37] The Soviets lowered a specially made 30 kiloton nuclear physics package into a 6-kilometre (20,000 ft) borehole drilled 25 to 50 metres (82 to 164 ft) away from the original (rapidly leaking) well. A nuclear explosive was deemed necessary because conventional explosives both lacked the necessary power and would also require a great deal more space underground. When the device was detonated, it crushed the original pipe that was carrying the gas from the deep reservoir to the surface and vitrified the surrounding rock. This caused the leak and fire at the surface to cease within approximately one minute of the explosion, and proved to be a permanent solution. An attempt on a similar well was not as successful. Other tests were for such experiments as oil extraction enhancement (Stavropol, 1969) and the creation of gas storage reservoirs (Orenburg, 1970).[38]
Notable offshore well blowouts
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Further reading:For more information, please visit blowout preventer companies.
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Data from industry information.[1][39]
See also
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References
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A blowout preventer (BOP) (pronounced B-O-P)[1] is a specialized valve or similar mechanical device, used to seal, control and monitor oil and gas wells to prevent blowouts, the uncontrolled release of crude oil or natural gas from a well. 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.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 blowout threatens. 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 term BOP is used in oilfield vernacular to refer to blowout preventers. The abbreviated term preventer, usually prefaced by a type (e.g. ram preventer), is used to refer to a single blowout preventer unit. A blowout preventer may also simply be referred to by its type (e.g. ram). The terms blowout preventer, blowout preventer stack and blowout preventer system are commonly used interchangeably and in a general manner to describe an 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 lines, control pods, hydraulic accumulators, test valve, kill and choke lines and valves, riser joint, hydraulic connectors, and a support frame.
Two categories of blowout 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. 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 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. Blowout preventers do not always function correctly. An example of this is the Deepwater Horizon blowout, where the pipe line going through the BOP was slightly bent and the BOP failed to cut the pipe.
Use
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The Lucas Gusher at Spindletop, Texas (1901)Blowout preventers come in a variety of styles, sizes and pressure ratings. Several individual units serving various functions are combined to compose a blowout preventer stack. Multiple blowout 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 blowout preventer system are to:
Additionally, and in performing those primary functions, blowout preventer systems are used to:
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, 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 blowout 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 downhole 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 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 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.[2]
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[citation needed]. 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.
Types
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BOPs come in two basic types, ram and annular. Both are often used together in drilling rig BOP stacks, typically with at least one annular BOP capping a stack of several ram BOPs.
Ram blowout preventer
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Blowout preventer diagram showing different types of rams. (a) blind ram (b) pipe ram and (c) shear ram.The ram BOP was invented by James Smither Abercrombie and Harry S. Cameron in 1922, and was brought to market in 1924 by Cameron Iron Works.[3]
A ram-type BOP is similar in operation to a gate valve, but uses a pair of opposing steel plungers, rams. The rams extend toward the center of the wellbore to restrict flow or retract 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, are of four common types: pipe, blind, shear, and blind shear.
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. A pipe ram should not be closed if there is no pipe in the hole.
Blind rams (also known as sealing rams), which 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.
Patent Drawing of a Varco Shaffer Ram BOP Stack. A shear ram BOP has cut the drillstring and a pipe ram has hung it off. Schematic view of closing shear bladesShear 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 shearing the pipe.
Blind shear rams (also known as shear seal rams, or sealing shear rams) are intended 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. The upper portion of the severed drill string is freed from the ram, while the lower portion may be crimped and the “fish tail” captured to hang the drill string off the BOP.
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 around the drill string and pressurizing the annulus, the BOP is pressure-tested for proper function.
The original ram BOPs of the 1920s were simple and rugged manual devices 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 jack. 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 1940s. 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.
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. In that way, for example, a pipe ram BOP can be converted to a blind shear ram BOP.
Shear-type ram BOPs require the greatest closing force in order to cut through tubing occupying the wellbore. Boosters (auxiliary hydraulic actuators) are frequently mounted to the outer ends of a BOP's hydraulic actuators to provide additional shearing force for shear rams. If a situation arises whereby the shear rams are to be activated, it is best practice for the Driller to have the string spaced as to ensure the rams will shear the body of the drillpipe as opposed to having a tooljoint (much thicker metal) across the shear rams.
Ram BOPs are typically designed so that well pressure will help maintain the rams in their closed, sealing position. That is achieved by allowing fluid to pass through a channel in the ram and exert pressure at the ram's rear and toward the center of the wellbore. 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 as common.[citation needed]
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 hydraulic 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 highest-capacity large-bore ram blowout preventer on the market, as of July 2010, was Cameron's EVO 20K BOP, with a hold-pressure rating of 20,000 psi, ram force in excess of 1,000,000 pounds, and a well–bore diameter of up to 18.75 inches.[citation needed]
Annular blowout preventer
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Patent Drawing of Original Shaffer Spherical-type Blowout Preventer (1972) Diagram of an annular blowout preventer in open and fully closed configurations. The flexible annulus (donut) in blue is forced into the drillpipe cavity by the hydraulic pistons.The annular blowout preventer was invented by Granville Sloan Knox in 1946; a U.S. patent for it was awarded in 1952.[4][better source needed] Often around the rig it is called the "Hydril", after the name of the original manufacturer of such devices.
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.e., moved vertically while pressure is contained below) through an annular preventer by careful control of the hydraulic closing pressure. 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 top 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 sphincter, sealing 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.[citation needed]
The original type of annular blowout preventer used a “wedge-faced” (conical-faced) piston. 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.[citation needed]
In 1972, Ado N. Vujasinovic was awarded a patent for a variation on the annular preventer known as a spherical blowout preventer, so-named because of its spherical-faced head.[5][better source needed] As the piston rises the packing unit is thrust upward against the curved head, which constricts the packing unit inward. Both types of annular preventer are in common use.[original research?]
Control methods
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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:[citation needed]
Two control pods are provided on the BOP for redundancy. Electrical signal control of the pods is primary. Acoustical, ROV intervention and dead-man controls are secondary.
An emergency disconnect system/sequence (EDS) disconnects the rig from the well in case of an emergency. The EDS is also intended to automatically trigger the deadman switch, which closes the BOP, kill and choke valves. The EDS may be a subsystem of the BOP stack's control pods or separate.[citation needed]
Pumps on the rig normally deliver pressure to the blowout preventer stack through hydraulic lines. Hydraulic accumulators are on the BOP stack enable closure of blowout preventers even if the BOP stack is disconnected from the rig. It is also possible to trigger the closing of BOPs automatically based on too high pressure or excessive flow.[citation needed]
Individual wells along the U.S. coastline may also be required to have BOPs with backup acoustic control.[citation needed] General requirements of other nations, including Brazil, were drawn to require this method.[citation needed] BOPs featuring this method may cost as much as US$500,000 more than those that omit the feature.[citation needed]
Deepwater Horizon blowout
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A robotic arm of a Remotely Operated Vehicle (ROV) attempts to activate the Deepwater Horizon Blowout Preventer (BOP), Thursday, April 22, 2010.During the Deepwater Horizon drilling rig explosion incident on April 20, 2010, the blowout preventer should have been activated automatically, cutting the drillstring and sealing the well to preclude a blowout and subsequent oil spill in the Gulf of Mexico, but it failed to fully engage. Underwater robots (ROVs) later were used to manually trigger the blind shear ram preventer, to no avail.
As of May 2010 it was unknown why the blowout preventer failed.[6] Chief surveyor John David Forsyth of the American Bureau of Shipping testified in hearings before the Joint Investigation[7] of the Minerals Management Service and the U.S. Coast Guard investigating the causes of the explosion that his agency last inspected the rig's blowout preventer in 2005.[8] BP representatives suggested that the preventer could have suffered a hydraulic leak.[9] Gamma-ray imaging of the preventer conducted on May 12 and May 13, 2010 showed that the preventer's internal valves were partially closed and were restricting the flow of oil. Whether the valves closed automatically during the explosion or were shut manually by remotely operated vehicle work is unknown.[9] A statement released by Congressman Bart Stupak revealed that, among other issues, the emergency disconnect system (EDS) did not function as intended and may have malfunctioned due to the explosion on the Deepwater Horizon.[10]
The permit for the Macondo Prospect by the Minerals Management Service in 2009 did not require redundant acoustic control means.[11] Insofar as the BOPs could not be closed successfully by underwater manipulation (ROV Intervention), pending results of a complete investigation, it is uncertain whether this omission was a factor in the blowout.
Documents discussed during congressional hearings June 17, 2010, suggested that a battery in the device's control pod was flat and that the rig's owner, Transocean, may have "modified" Cameron's equipment for the Macondo site (including incorrectly routing hydraulic pressure to a stack test valve instead of a pipe ram BOP) which increased the risk of BOP failure, in spite of warnings from their contractor to that effect. Another hypothesis was that a junction in the drilling pipe may have been positioned in the BOP stack in such a way that its shear rams had an insurmountable thickness of material to cut through.[12]
It was later discovered that a second piece of tubing got into the BOP stack at some point during the Macondo incident, potentially explaining the failure of the BOP shearing mechanism.[13] As of July 2010 it was unknown whether the tubing might have been casing that shot up through the well or perhaps broken drill pipe that dropped into the well. The DNV final report indicated that the second tube was the segment of the drill string that was ejected after being cut by the blow out preventer shears.
On July 10, 2010, BP began operations to install a sealing cap, also known as a capping stack, atop the failed blowout preventer stack. Based on BP's video feeds of the operation the sealing cap assembly, called Top Hat 10, included a stack of three blind shear ram BOPs manufactured by Hydril (a GE Oil & Gas company), one of Cameron's chief competitors. By July 15 the 3 ram capping stack had sealed the Macondo well, if only temporarily, for the first time in 87 days.
The U.S. government wanted the failed blowout preventer to be replaced in case of any pressure change that occurs when the relief well intersected with the well.[14] On September 3, 2010, at 1:20 p.m. CDT the 300 ton failed blowout preventer was removed from the well and began being slowly lifted to the surface.[14] Later that day a replacement blowout preventer was placed on the well.[15] On September 4 at 6:54 p.m. CDT the failed blowout preventer reached the surface of the water and at 9:16 p.m. CDT it was placed in a special container on board the vessel Helix Q4000.[15] The failed blowout preventer was taken to a NASA facility in Louisiana for examination[15] by Det Norske Veritas (DNV).
On March 20, 2011, DNV presented their report to the US Department of Energy.[16] Their primary conclusion was that while the rams succeeded in partly shearing through the drill pipe they failed to seal the bore because the drill pipe had buckled out of the intended line of action of the rams (because the drill string was caught at a tool joint in the upper annular BOP valve), jamming the shears and leaving the drill string shear actuator unable to deliver enough force to complete its stroke and fold the cut pipe over and seal the well. They did not suggest any failure of actuation as would be caused by faulty batteries. The upper section of the blow out preventer failed to separate as designed due to numerous oil leaks compromising hydraulic actuator operation, and this had to be cut free during recovery.
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