Blowout preventers (BOPs)
Blowout preventers (BOPs), in conjunction with other equipment and techniques, are used to
close the well in and allow the crew to control a kick before it becomes a blowout.
Blowout preventer equipment should be designed to:
1. Close the top of the hole.
2. Control the release of fluids.
3. Permit pumping into the hole.
4. Allow movement of the inner string of pipe.
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BOPs  equipment  are  selected  based  on  the  maximum  expected  wellbore  pressures.  The
pressure  rating,  size  and  number  of  BOP  components  must  be  determined  by  the  Drilling
Engineer prior to drilling the well.
Basic  types  of  blowout  preventers  on  drilling  rig  are:  annular  preventers,  ram  preventers,
rotational preventers and diverters. BOPs are rated by API as 3M (3000 psi), 5M, 10 M and 15
M. For HPHT, BOPS are either 15 M or 20 M.
The recommended component codes for designation of BOP stack arrangements are as

• A = annular type blowout preventer
• G = rotating head
• R = single ram type preventer with one set of rams, blind or pipe, as
operator prefers
• Rd = double ram type preventer with two sets of rams, positioned as
operator prefers
• Rt = triple ram type preventer with three se ts of rams, positioned as
operator prefers
• S = spool with side outlet connections for choke and kill lines
• M = 1,000 psi (68.95 bar) rated working pressure

BOP components are typically described upward from the uppermost piece of the permanent
wellhead equipment, or from the bottom of the BOP stack: for example 10K – 13 5/8 – SRRA
This BOP stack would be rated 10000 psi (69 MPa) working pressure, would have a through
bore of 13 5/8 inches (34,61 cm)
In  the  BOP  stack  they  are  always  positioned  in  such  way,  that  annular  preventer  is  the
working preventer positioned on the top of the stack, and ram preventer is on the bottom as
the backup. Working preventer is always positioned far from the source of danger, to be in
position to change it if fails.


The annular blowout preventer was invented by Granville Sloan Knox in 1946; a U.S. patent
for it was awarded in 1952.[3] Often around the rig it is called the "Hydril", after the name of
one of the manufacturers 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 anelastomeric 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.


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