If primary control is lost and formation fluids start to
flow into the well, secondary well control is initiated by
closing the blowout preventers to seal off the annulus.
This stops mud leaving the well at the surface. As fluid
enters the well from the kicking formation, pressure in
the well will increase until the total pressure exerted by
the mud on the kicking formation equals the formation
The aim of secondary control is to stop the flow of
fluids into the wellbore and eventually allow the influx
to be circulated to surface and safely discharged, while
preventing further influx downhole. Now we can restore
the primary well control.
It sometimes happens that the blowout preventer
equipment fails or the hole starts to allow fluid to leak
away into an underground formation. Secondary control
cannot be maintained, and formation fluid again starts
to enter the wellbore. This is now a dangerous situation.
If control is not restored, the end result is a blowout.
Tertiary control has to be applied to try to stop the flow.
Tertiary control involves pumping substances into the
wellbore to try to physically stop the flow downhole.
This may involve pumping cement (with a high risk of
having to abandon the well afterwards). However, there
AAPG Suez Student Chapteris another method that may be employed, called a barite
A barite plug is set by mixing a heavy slurry of barite in
water or diesel oil. It has to be kept moving while
mixing and pumping. Once the slurry is in position
downhole and pumping stops, the barite rapidly settles
out to form an impermeable mass that will hopefully
stop the flow of formation fluid. The main risk is that if
pumping stops with the slurry inside the pipe, barite will
settle out in the pipe and plug the drillstring
Blowout Preventer Stack
The primary function of the BOP is to form a rapid and
reliable seal around the drillstring or across the empty
hole (if no pipe is in the hole) so as to contain downhole
pressures. There are currently two types of preventer
available that allow this seal to be formed
Bag-type preventer (or annular preventer)
A bag preventer contains a large rubber seal, which is
circular if viewed from above and conical if viewed
from the side. This is held inside a steel chamber.
Below the rubber element is a hydraulically
operated piston with a matching conical shape on
top to fit the rubber underside. As the piston moves
up, the rubber element is compressed by the cover
above it and pushed inwards by the cone profile.
The element can distort to allow it to seal around
any smooth object in the wellbore, whether it is a
round pipe or tool joint or a square kelly. It can also
seal on the open hole, but the level of rubber
element distortion necessary will seriously shorten
the useful life of the element. The rubber seal,
called a packing, is expensive and awkward to
Moving pipe in a closed well when the well is under
pressure is called stripping. The is possible because the
rubber element can move to accommodate the thicker
tool joints moving down through the element.
The other type of preventer uses a pair of large
steel rams that shut under high hydraulic pressure,
with great force. These rams are interchangeable
and are of different types:
- fixed pipe ram: the seal is sized to fit one
outside diameter only.
- Variable bore pipe ram: the seal element can
accommodate a narrow range of diameters. It
can only seal on round pipe only.
- Blind rams: blind rams are designed to seal on
the open hole.
- Blind-share rams: blind-share rams have
blades incorporated that can cut through pipe.
- Casing share rams: these are heavy-duty share
rams that do not seal but can cut through heavy
pipe, such as casing.
BOP diagram showing different types of rams. (a)blind
ram. (b)pipe ram and (c)shear ram
- Normally, a BOP stack would have at least one
bag preventer and two ram preventers.
- Stacks for deeper wells might have up to four
ram preventers and two annular preventers.
- The ram preventers generally have a higher
pressure rating and are always installed below
the bag preventers.
- If only two ram preventers are used, the bottom
set will normally be blind-shear rams, and the
upper set will be pipe rams. One reason for
placing the blind rams on the bottom is that if
the pipe rams or annular leaks, it is possible to
close the blind rams below and fix the leak above
Below the rams are pipes that come out to the side.
These are called side outlets and are used to allow flow
out of or into the annulus during well killing operations.
- One side connects to the standpipe manifold to
allow flow to be directed into the annulus. This is
called the kill line.
- The opposite side connects to a manifold of valves
and chokes. This is called the choke line, and its
purpose is to allow flow out of the annulus to be
A choke valve allows fluid to flow through it, but it has
a variable sized opening. This allows mud to flow out
of the annulus but at the same time keeps pressure on
BOP control systems
1- BOP units (bag and ram preventers and some
valves) are moved using hydraulic fluid under
pressure to provide this pressure, a hydraulic
control system is used that contains several
2- A reserve hydraulic fluid tank holding fluid at
3- A set of bottles holding fluid under high pressure
(usually 3,000 psi) with pressurized nitrogen.
4- A high-pressure manifold connected to the bottle
5- A low-pressure manifold that contains fluid at the
working pressure of the ram preventers
6- (usually 1,500 psi).
7- A pressure regulator that feeds fluid from the highpressure manifold to the low-pressure manifold and
that reduces the pressure to the working pressure.
8- A set of valves attached to the low-pressure
manifold that can direct working pressure fluid to
the rams (to open or to close them) and that directs
exhaust fluid back to the reserve hydraulic fluid
9- A valve that controls the opening and closing of the
10- A pressure regulator that feeds fluid from the lowpressure manifold to the bag preventer control
11- Two sets of pumps to maintain system pressure.
One set is driven by compressed air from the rig air
system, the other is powered by electricity.
Subsea BOP systems
- On floating rigs, the BOP is attached to the top of
the surface casing at the seabed. A subsea BOP
contains extra control systems when compared to a
- The hydraulic control system is also open ended in
that hydraulic fluid is exhausted to the sea rather
than being returned to the control system. Thehydraulic fluid in this case is water mixed with a
nontoxic soluble oil so that pollution is avoided
Kick detection equipment
There are two main kick detection systems that give a
direct indication of a kick:
The pit volume totalizer
that can display the volume in any particular tank and
can also add up all of the surface active volumes so that
any change in the total surface volume may be detected.
The PVT also includes alarms that can be set so that
changes beyond a set amount lost or gained will cause
an alarm to sound.
It provides a readout showing the total volume of
drilling fluid held on the surface. If this total increases,
and the increase is not due to the mud engineer adding
chemicals or fresh mud to the system, a kick is
The flow indicator
This system consists of an instrument attached to a
paddle that sits in the flowline from the annulus. This
paddle is pushed up by the returning mud stream; the
amount it is pushed depends on the flow rate, among
other things. If the flow rate should increase, an alarm
will sound. If the flow rate out increases but the mud
pump speed has not been increased, it is possible that
the extra flow out is due to an influx entering the
Generally the flow indicator will give the first
positive indication of a kick, followed by an increase in
the active volume. However, the paddle-type flow
indicator is prone to false alarms because of cuttings and
other debris that may stick to the paddle or build up
If the surface instruments indicate that a kick is in
progress while drilling, normally the driller will stop
drilling, pick up the drillstring so that the bit is above
the bottom of the hole, and stop the pumps. A visual
check is then made by looking down through the rotary
table, into the bell nipple, at the level of mud in the
annulus. If the well is in fact kicking, the mud in the
annulus will still be moving upwards even though the
pumps are shut down. Having confirmed a kick, the
driller will then close the BOP as quickly as possible
and will then notify the toolpusher and drilling
supervisor in charge of the rig.
If the permeability of the flowing formation is high,
the kick can develop very quickly. A larger drilled hole
will also allow influx to flow in faster, but this is
compensated for to an extent because the capacity of the
hole is greater in a larger hole. It is also possible that if
permeability is very low, little or no influx enters the
wellbore even though mud hydrostatic is less than
formation pore pressure.
This article described the three levels of well control
(primary, secondary, and tertiary). Well control
equipment was covered in some detail, including
blowout preventers and control systems, chokes, and
kick detection equipment.
- Drilling Technology in nontechnical
language, steve devereux, Editor.