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Blowout Preventers (BOPs) |
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Oil and gas in the ground can be under tremendous pressure. Therefore, when the drill bit enters the formation containing the hydrocarbons a blowout may occur. Oil and gas then flow up the annulus with the returning mud. When the hydrocarbons reach the drilling rig they can ignite, causing a blowout that often causes an explosion and fire. In the case of Deepwater Horizon the initial explosion and subsequent fire was sufficient to cause eleven fatalities and to destroy the drilling rig. Figure 1 is another photograph of an uncontrolled blowout - also in southeast Texas in the early twentieth century. Because there was no way of stopping a flow such as this the drillers in those days had to wait until the pressure in the well had reduced to the point where it could be capped.
Figure 1
Figure 2 shows the offshore spill that followed a blowout off the California coast in 1969. Further information to do with this event is provided at our Santa Barbara spill page.
Figure 2
Kicks and BlowoutsWhen discussing backflow of fluids up the annulus, the terms “kick” and “blowout” are used. It is important to draw a clear distinction between these two terms. A kick can occur whenever the drill enters a formation that contains fluids at higher pressure than that imposed by the mud. The fluid does not have to be hydrocarbon. For example, if the drill enters a region of water under pressure then the water will flow back up the annulus with the mud. The symptom of a kick is that the flow of returning mud is greater than the flow into the string. As the drill bit approaches the oil or “pay zone”, the drilling crew closely monitors the amount of fluid in the mud storage tanks as well of the formation pressure to determine if a kick is occurring. Kicks are controlled by adjusting the weight of the drilling mud that is pumped down the drill string. The aim is to make sure that the drilling mud is of sufficient density that the pressure it exerts on the formation is greater than the pressure of the well, thus preventing backflow of fluids. If the kick is not controlled through the use of higher density mud then one of the preventers in the BOP stack can be closed manually. A blowout is a much more serious event because it implies (a) that the normal control measures (such as increasing mud weight) have failed, and (b) that the BOP has also failed. Control of Kicks and BlowoutsKicks are controlled by adjusting the weight of the drilling mud that is pumped down the drill string. The aim is to make sure that the drilling mud is of sufficient density that the pressure it exerts on the formation is greater than the pressure of the well, thus preventing the oil and gas from flowing upward. As the drill bit approaches the oil or “pay zone”, the drilling crew closely monitors the amount of fluid in the mud storage tanks as well of the formation pressure to determine if a kick is occurring.
In the event that normal well control procedures do not work, a Blowout Preventer, installed at the
wellhead as shown in Figure 3, prevents the oil and gas from flowing up the annulus. (The
sketch actually shows a BOP stack made up of a series of individual preventers.) The stack is
supported by the 18” casing
— the sea floor itself does
not have sufficient strength to support the stack’s massive weight
(the BOP used at Deepwater Horizon weighed 450 tons). In the Gulf of
Mexico, much of the sea floor is particularly soft because it
consists of deposits from the outflow of the Mississippi river.
Figure 3
A BOP is analogous to a relief valve on a process plant - it represents the last line of defense. It has been said that, “relief valves should always work, relief valves should never work”. What is meant by this aphorism is that, being the last line of defense, a relief valve must always work when called upon to do so. At the same time, other safeguards, such as instrumentation and troubleshooting procedures should always take control of a high pressure situation before a relief valve is ever needed. The same principle applies to BOPs. They should always work when called upon to do so, but kicks and potential blowouts should be managed through the use of mud weight and normal operating procedures. Because BOPs are so important to safe operations, their maintenance and testing is a high priority activity, and is generally closely scrutinized by the regulatory authorities. (Testing procedures for U.S. operations are provided in 30 CFR 250.407.) Figure 3 shows that the BOP stack is made up of different types of preventer: annual, blind ram and shear ram (these terms are discussed in more detail below). The make-up of an actual BOP stack will vary according to the requirements of that particular well. It is important to understand that the annular and blind ram preventers only seal the annulus through which return mud and oil and gas are rising. In the event of a blowout, the drill pipe, down which the mud is flowing, is sealed at the drilling rig. Only the shear ram cuts through the drill pipe itself. This is an irreversible action — the shear ram should only be used as a last resort. Once the BOP has been activated, heavy mud is pumped into the well through the kill line, and out through the choke. Once the situation has been stabilized the BOP can be re-opened (unless the shear ram was used). Figure 4, which is taken from the OSHA web site , shows an annotated BOP stack. Working from the top down, the components of the stack are:
Figure 4
Ram Preventers
These first BOPs (ASME 2003) consisted of a
single preventer that was cranked closed by operators using wrenches
(this was when all oil wells were onshore). Modern BOPs are closed
hydraulically. The configuration of the preventers is optimized
to provide maximum pressure integrity, safety and flexibility. For
example, in a multiple ram configuration, one set of rams might be
fitted to close on 5” diameter drillpipe, another set configured for
4½” drillpipe and a third fitted with blind rams to close on an open
hole. Pipe RamsA picture of an early ram preventer is provided in Figure 4; it shows the characteristic T-shape of these devices.
Figure 4
Each half of the ram BOP consists of a flat plate that slides across the annulus. The plate has a circular shape cut out of it. The radius of the cut out is the same as that of the drill pipe. The plates or rams have elastomer surface. If they are called upon to operate they slide toward one another forming a seal around the drill pipe, thus preventing oil and gas from flowing up the annulus. Figure 5 shows the two halves of the ram in their normal operating positions. They are retracted such as that they do not interfere with the normal flow of return mud.
Figure 5
Figure 6 Blind Rams
A blind ram is a pipe ram without the cutouts in the flat plates. They are used when the string is empty,
i.e., when there is no
drill pipe present.
Shear RamsShear rams are similar to blind rams except that they do not have a semi-circular shape; instead they are fitted with a tool steel-cutting surface to enable the ram BOPs to completely shear through drillpipe, which is then hung from the ram blocks. The use of this type of preventer is very much a last resort since the drill string then has to be completely refabricated. A potential problem with the use of shear rams is that they may have to close on a joint in a section of the drill pipe (the joints connect sections of drill pipe and occur once every 30 ft. or so). Because of the extra thickness created by the joint, the shear ram might not completely sever the pipe. To overcome this problem some BOP stacks contain two shear rams, thus guaranteeing that one of them, at least, will shear the string. Annular Preventers
An annular
preventer, also known as a spherical preventer, is shaped like a
doughnut. It is fabricated from reinforced rubber reinforced with
steel ribs. When activated, the
rubber sealing
element forms a seal around the drill string. If the drill stem is
not present, the annular preventer closes on the open hole. One
advantage that they have over ram preventers is that they can close
over a wider range of tube sizes (including an open hole). However
they are not typically rated for the highest pressures that ram
preventers can control. Unlike a ram BOP, which closes with a sharp horizontal motion, an annular BOP closes around the drill string in a smooth simultaneous upward and inward motion. The geometry of this movement reduces internal stresses and friction between the BOP body and the sealing element, resulting in a longer field life with less maintenance. The annular design also allows for it to be operated at a lower operating pressure, reducing the number of hydraulic accumulators necessary and thereby reducing the cost and complexity of the operation. Activating the BOPA BOP is closed using hydraulic systems. These
systems can be activated either manually or automatically. Automatic
operation can be
activated if the system detects either high flow or high pressure. The subsea control system must react quickly. The minimum requirement for BOPs to close is 45 seconds or less. Annular BOPs must close within 60 seconds. Kill and Choke LinesFigure 3 shows kill and choke lines below the rams. After the BOP has closed heavy mud is pumped through the kill line in order to regain well control. The mud returns through the choke line to the drilling rig, where it is recirculated. Once pressure control of the well has been achieved the kill and choke lines can be closed, the preventers opened and drilling can resume. Rules and Standards
An operation as important as that of a BOP is naturally governed
by a number of different rules and standards (depending on the
national authorities). In the United States the standard applied by
the Bureau of Safety and Environmental Enforcement (BSEE)
is 30 CFR Title 30, Section 250.406. |
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