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]
Link to Yulin Machinery
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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Data from industry information.[1][39]
See also
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References
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When a well is drilled on land, an interface is required between the individual casing strings and the blowout preventer (BOP) stack. This interface is required for four main reasons:
Pressure Containment
When drilling a well on land, a spool wellhead system is traditionally used, as shown in Fig. 8.1. This wellhead is considered a "build as you go" wellhead system that is assembled as the drilling process proceeds. The spool system consists of the following main components:Fig. 8.1—Illustration of a typical land wellhead system and casing program (all figures in this chapter are courtesy of Dril-Quip).
Fig. 8.2—Photo of a starting casing head and installation components. This casing head is typical of a thread-on or weld-on configuration used in land drilling operations.
Fig. 8.3—Photo of a starting casing head and slip-and-seal assembly with installation components. This casing head has a gusseted base plate typically seen in jackup drilling operations.
Fig. 8.4—Photo of a typical intermediate casing head and additional components required to assemble it during the drilling operation.
Fig. 8.5—Photo of a typical tubing head with installation components.
Load-Carrying Components
When drilling a well on land, a spool wellhead system is traditionally used, as shown in. This wellhead is considered a "build as you go" wellhead system that is assembled as the drilling process proceeds. The spool system consists of the following main components:The starting casing head (see) attaches to the surface casing (conductor) by either welding or threading on to the conductor. The top of the starting casing head has a flange to mate with the bottom of the BOP. The flange must meet both size and pressure requirements. The starting casing head has a profile located in the inside diameter (ID) that will accept a slip-and-seal assembly to land and support the next string of casing. The slip-and-seal assembly transfers all of the casing weight to the conductor while energizing a weight-set elastomeric seal.The intermediate casing spool is typically a flanged-by-flanged pressure vessel with outlets for annulus access (see). The intermediate casing spool (or spools) is installed after each additional casing string has been run, cemented, and set. The bottom section of each intermediate casing spool seals on the outside diameter (OD) of the last casing string that was installed. The bottom flange will mate with the starting casing head or the previous intermediate casing spool. The top flange will have a pressure rating higher than the bottom flange to cope with expected higher wellbore pressures as that hole section is drilled deeper.The intermediate casing spool also incorporates a profile located in the ID, which accepts a slip-and-seal assembly similar to the one installed in the starting casing head. This slip and seal will be sized in accordance with the casing program.The tubing spool, as shown in, is the last spool installed before the well is completed. The tubing spool differs from the intermediate spool in one way: it has a profile for accepting a solid body-tubing hanger with a lockdown feature located around the top flange. The lockdown feature ensures that the tubing hanger cannot move because of pressure or temperature. The flange sizes vary in accordance with pressure requirements.
Casing weight is transferred to the starting casing head and intermediate spools with two different types of hanger systems:
Fig. 8.6—Photo of a typical weight-set slip-and-seal assembly with casing-head installation components.
Fig. 8.7—Illustration (cutaway) of a mandrel-type tubing hanger.
Annulus Seals
The seals used on spool wellhead systems are traditionally elastomeric. This is primarily because the seal must be energized against the casing-bowl ID and must also seal against the rough finish of the casing OD.Fig. 8.8—Illustration of a weight-set slip-and-seal casing-hanger assembly.
Fig. 8.9—Photos of the wear bushings for a typical land drilling wellhead system.
Fig. 8.10—Photo of the wear bushing running tools. These tools are also used to test the BOP stack.
Annulus Access
The slip-and-seal casing-hanger assembly () has an OD profile that mates with the internal profile of the starting casing head and intermediate casing spools. Integral to this casing-hanger assembly is a set of slips with a tapered wedge-type back and serrated teeth that bite into the OD of the casing being suspended.When the casing has been run and cemented, the BOP is disconnected from the casing spool and lifted up to gain access to the spool bowl area. After the slip-and-seal casing-hanger assembly is installed, the traveling block will lower the casing and set a predetermined amount of casing load onto the slip-and-seal casing-hanger assembly. The teeth on the slips will engage the pipe OD and transfer the suspended weight of the casing to the starting casing head. As the slips travel down, they are forced in against the casing, applying greater and greater support capacity. As the slips continue to engage the pipe, a load is placed on the automatic weight-set elastomeric seal assembly, sealing the annulus between the casing and the casing head. This installation creates a pressure barrier and isolates the annular pressure below the slip-and-seal casing hanger from the wellbore.Traditionally, mandrel hangers () are used only to suspend tubing from the tubing head. Occasionally, they can also be used in intermediate casing spools as an alternative to the slip-and-seal casing-hanger assembly. The mandrel hanger is a solid body with a through-bore ID similar to that of the tubing or casing run below, and it also has penetrations for downhole safety valve line(s) and temperature and pressure gauges, if required. Traditionally in spool wellheads, elastomeric seals are used to seal the annulus between the casing-spool body and the casing or tubing hanger.The seals used on spool wellhead systems are traditionally elastomeric. This is primarily because the seal must be energized against the casing-bowl ID and must also seal against the rough finish of the casing OD.This elastomeric sealing system is used for the slip-and-seal assembly as well as the bottom of the intermediate casing or tubing spools. The slip-and-seal assembly () provides a primary annulus seal, while the elastomeric seal in the bottom of each casing and tubing spool also provides a seal. The casing-spool flange connection becomes a secondary seal for both annulus and wellbore pressure. The elastomeric seals are manufactured using different materials to allow for various pressures, produced fluids, and other environmental conditions. The exception is the seal between each flange face, which is a metal-to-metal sealing ring gasket that provides a pressure-tight seal between each of the spool flanges. Ring gaskets are also used between the wellhead and the BOP stack, as well as the valves used for annulus access.While drilling the well, it is required that the seal bores in each of the intermediate casing spools and tubing spools be protected. A series of wear bushings () are supplied to protect the seal areas discussed during the drilling operation. The wear bushings are run on a drillpipe tool () with J-lugs located on the OD that interface with J-slots located in the top ID section of the wear bushing.It is also required that the flanged connections between each spool and the BOP be tested during the drilling and completion phases. The tools required are available from the equipment supplier. The tool used for testing the BOP is typically a plug type with a heavy-duty elastomer seal.
For onshore wells, during the drilling operation, access to each annulus is required for the following reasons:
Product Material Specifications
When ordering wellhead equipment, the following should be considered:
Fig. 8.11—Tables showing typical gate-valve sizes (above) and trims (below). These trims are also applicable to surface wellheads.
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