refers to the control of downhole formation pressures penetrated by the well.
There are three distinct well control levels that may occur during
Primary well control
The first line of defense is primary well control, which results
from maintaining the density of the drilling fluid such that
hydrostatic pressure at all depths where formations are exposed exceeds
formation pore pressures
Mud hydrostatic pressure > Formation pore pressure
When a kick is taken, primary control has been lost for some
reason. There are four main reasons why primary control might be lost
during drilling operations :
1. The well penetrates an overpressured zone with a higher formation pressure than mud hydrostatic pressure.
2. A weak downhole formation allows sufficient mud to leave the
wellbore that the level of mud in the annulus drops. Since hydrostatic
pressure = gradient × depth (of the fluid column), if the top of the
column drops, hydrostatic pressure along the wellbore decreases. If it
drops far enough, hydrostatic overbalance on a permeable formation
exposed somewhere else may be lost, allowing fluids to enter the well.
3. The hole is not properly filled when pulling out of the hole.
As steel is pulled out of the well, it has to be replaced by mud. If
the driller does not keep the hole full while pulling out, the mud level
in the annulus will drop, and hydrostatic pressure will reduce.
4. Swabbing operations may also affect primary control. If the
drillstring is pulled up with sufficient speed, the reduction in
pressure at the bottom can be enough to allow formation fluids to enter
Secondary well control
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 pore
pressure. The pressure exerted by the mud equals mud hydrostatic
Mud hydrostatic pressure + Surface pressure Formation pore pressure
The figure shows the situation after closing the blowout
preventer. Fluid influx has entered the well, the blowout preventer is
closed, and the pressures have stabilized. Notice that the influx is in
the annulus. The density of all the fluids in the annulus is not known.
However, the drillpipe is full of clean mud of known density.
As the mud hydrostatic pressure in the drillpipe and surface
pressure are both known, the pressure at the bottom of the well can be
The objective now is to restore primary control. Two things are necessary to do this :
- Remove all of the influx out of the well
- Replace the mud in the well with a fluid that is heavy
enough to again exert sufficient hydrostatic pressure to control the
downhole formation pressures with the BOP open.
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
calling for extreme measures to restore control. 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 is another method that may
be employed, called a barite plug.
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
Blowout Preventer Stack
When planning and drilling wells, the assumption is made that a
kick is always possible. Even if the well is the 100th drilled in the
immediate area, primary control can still be lost for some reason. This
is why blowout preventers (BOPs) are always used once surface casing has
been cemented in place.
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. Most
BOPs contain at least one of each type as the different characteristics
of each are useful for different operations.
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
replace. Apart from sealing on irregular-shaped tubulars, the annular
preventer can also be used to allow pipe movement in or out of the well
under pressure. Moving pipe in a closed well when the well is under
pressure is called stripping. This may be useful, for instance, if a
kick occurs when little or no pipe is in the hole. In order to kill the
well, heavy fluid has to be pumped through the drillstring to the bottom
of the hole. If the pipe is not deep enough, more pipe can be added
until it is deep enough to kill the well by stripping pipe in through
the bag preventer. This is possible because the rubber element can move
to accommodate the thicker tool joints moving down through the element.
To strip in, the hydraulic closing pressure on the piston is
reduced until a slight amount of mud starts to leak through the seal.
This provides some lubrication. Grease is put onto the tool joints, and
the pipe is moved downwards slowly to minimize wear on the rubber seal.
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 :
1. Fixed pipe ram. The seal is sized to fit one outside diameter only.
2. Variable bore pipe ram. The seal element can accommodate a
narrow range of diameters, for example 3½" to 7". It can only seal on
round pipe, not square or hexagonal shapes (see fi g. 11–4).
3. Blind rams. Blind rams are designed to seal on the open hole.
4. Blind-shear rams. Blind-shear rams have blades incorporated
that can cut through pipe (though not through drill collars or casing)
and can also form a seal when closed.
5. Casing shear rams. These are heavy-duty shear rams that do
not seal but can cut through heavy pipe, such as casing. These are found
in subsea BOP stacks and are used if the rig needs to disconnect from
the BOP in an emergency. In this case, the ability to cut whatever pipe
is through the BOP is critical. A subsea BOP will also have a set of
blind-shear rams that can be closed after the casing shear rams have
Normally, a BOP stack would have at least one bag preventer and
two ram preventers, as shown in. BOP 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.
The side outlets have different names. 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 controlled. Chokes are described
Once the driller detects that a kick is in progress, one of the
BOP stack preventer units will be closed to seal the annulus of the
the pressure at the top of the well (inside the drillpipe and at
the top of the annulus) will be recorded. Once the pressures are
steady, the formation pore pressure (due to hydrostatic and surface
pressure) can be calculated. A plan can then be formulated to kill the
There is another vital item that forms part of the BOP
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 the annulus. The pointed part of the
needle moves in and out in respect to the choke bean. As the needle
moves in (to the right in the diagram), the gap closes. For a particular
flow rate through the choke, this will increase the pressure upstream
of the choke.
It would be possible to use a normal valve as a choke. However,
mud that contains solids (barite, bentonite, sand, or other drilled
particles) is quite abrasive when flowing through a restriction at high
pressure. A normal valve would soon erode and fail to hold pressure if
it were used to exert pressure on the flowing mud. A choke valve is
designed to handle this operation with minimum erosion, by its design
and by the use of tungsten carbide internal components. It is still
possible for the choke to become eroded during a well killing operation,
and so the rig must carry spares of these parts. There must also be
valves positioned upstream of the choke that can be closed to allow the
choke to be repaired.
BOP control systems
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 elements :
1. A reserve hydraulic fluid tank holding fluid at atmospheric pressure.
2. A set of bottles holding fluid under high pressure (usually 3,000 psi) with pressurized nitrogen.
3. A high-pressure manifold connected to the bottle system.
4. A low-pressure manifold that contains fluid at the working pressure of the ram preventers (usually 1,500 psi).
5. A pressure regulator that feeds fluid from the high-pressure
manifold to the low-pressure manifold and that reduces the pressure to
the working pressure.
6. 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
7. A valve that controls the opening and closing of the bag preventer.
8. A pressure regulator that feeds fluid from the low-pressure
manifold to the bag preventer control valve. Bag preventers operate at a
lower pressure than ram preventers (normally about 800 psi), but as the
seal element gets worn, higher pressure is required to make the bag
seal around pipe. This regulator is also used to lower the closing
pressure to the bag preventer if it is desired to strip pipe in through
the preventer, as described previously in this chapter.
9. 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. This provides some backup in the event of either the rig
air or electric system failing. The air-driven pumps give a higher flow
rate and generally pressure up the system to around 2,800 psi. The
electric pump tops up the system to the full pressure of 3,000 psi at a
lower flow rate.
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