Blowout prevention equipment

Quick refresher

BOP equipment is the upper part of the second barrier: the preventers, the choke and kill lines with their manifolds, the BOP control unit and the shut-off devices of the drill string. It does not only close the well. It also lets the crew kill the well.
The annular preventer squeezes its rubber packing element (a thick rubber ring) around a pipe of any shape. It also lets the crew pull the string through under pressure. Ram preventers close the hole with pairs of steel blocks, called rams, that slide together from the two sides. They are often built for a higher pressure, but each pair of rams does one job. Pipe rams close on a pipe of their own diameter, blind rams close an empty hole, and shear rams cut the pipe.
In the stack the annular preventer is at the top and the ram preventers are below it. Fluid leaves through an outlet below the closed element into the choke line. The crew pumps mud into the closed well through the kill line.
We choose the working pressure from the highest expected wellhead pressure, which is the formation pressure minus the gas column. Then we take the next higher step: 14, 21, 35, 70, 105 MPa. Every element of the wellhead layout that the well pressure can reach must have the same working pressure, up to and including the chokes of the manifold.
The energy that closes the preventers is stored in accumulators under the pressure of nitrogen. The usable fluid in a bottle is about half of its volume by the isothermal calculation (constant temperature). It is noticeably less when the bottle discharges fast.
At shallow depth, with only the conductor (the first, short casing pipe) set, the crew does not close the well. Instead, the crew sends the flow away with a diverter, because the rock under a shallow shoe (the bottom end of the casing) will not hold the pressure of a closed well.

Key relationships

p_{\text{wh}} = p_p - 0.00981\,\rho_{\text{g}}\,h

the highest expected wellhead pressure: the well is closed and full of gas (MPa, g/cm³, m)

p_{\text{ctrl}} \ge \dfrac{p_{\text{well}}}{K_{\text{cl}}}, \qquad K_{\text{cl}} = \left(\dfrac{d_{\text{pis}}}{d_{\text{rod}}}\right)^2

the control pressure needed to close the rams against the pressure in the well

V_{\text{use}} = V_{\text{bottle}}\,p_0\left(\dfrac{1}{p_{\min}} - \dfrac{1}{p_{\text{work}}}\right)

usable volume of fluid in an accumulator; the pressures are absolute and the temperature is constant

\Delta p = \dfrac{\rho\,q^2}{2\,C_d^2 A^2}

pressure drop across a choke when a liquid flows through it

Common pitfalls

Assuming that pipe rams will close on a tool joint (the thick threaded end of a pipe), on the kelly (the square or hexagonal pipe at the top of the string) or on a pipe of another diameter.
Judging the allowable pressure of a closed well by the preventer, not by the weakest element of the whole pressure shell (everything that holds the pressure of the closed well, down to the rock under the shoe).
Putting gauge pressures (pressures above atmospheric) into the accumulator calculation, or counting the whole volume of the bottle as usable.
Relying on a float valve (a one-way valve) in the drill string and not keeping an open ball valve on the rig floor (the working platform of the rig).
Closing the well on a kick from under the conductor, where the flow must be diverted.

After this lesson you can

explain the role of BOP equipment as part of the second barrier, and list what it must be able to do: close the well with any pipe in it or with none, and let fluid out or pump it in under pressure
describe how annular and ram preventers are built and what they can do, and what pipe rams, blind rams and shear rams are for
read the drawing of a preventer stack and explain the positions of the rams, the side outlets, the choke line and the kill line
choose the rated working pressure of the BOP equipment from the highest expected wellhead pressure
explain what the choke manifold (the valves and adjustable chokes that control the flow out of the closed well), the mud-gas separator (the vessel that takes gas out of the mud) and the BOP control unit are for, and estimate the usable volume of an accumulator (a bottle that stores the energy for closing the preventers)
name the devices that shut off the drill string from the inside, and explain why a diverter (a device that sends the flow away from the rig) is needed

The second barrier: what BOP equipment must be able to do

While the pressure of the mud column is higher than the pore pressure (the pressure of the fluid in the rock), the primary barrier holds the well (primary and secondary well control). BOP equipment is needed for the case when this barrier fails. Then formation fluid starts to flow into the well, and the crew must close the hole at the surface. But simply “plugging” the well is not enough. The crew must also circulate the formation fluid out (pump it out of the well with the mud) and replace the mud with a heavier one (Well kill methods). So the equipment must both close the well and let the crew control the pressure in it. In detail, it must be able to do these things:

close the annulus (the ring-shaped space around the pipe) around any pipe that is at the wellhead: drill pipe, drill collar (a very thick, heavy pipe), casing or kelly (the square or hexagonal pipe at the top of the string)
close the whole hole when there is no pipe in it
as a last resort, cut the pipe and close the hole
let fluid out of the closed well through the choke (an adjustable valve that restricts the flow), and keep the pressure at a set value
let the crew pump mud into the closed well, both through the drill string and outside it
hold the weight of the string and allow the crew to lower or raise pipe under pressure
work fast, and independently of the electric power of the rig

No single preventer can do all this, and any element can fail. So the crew stacks preventers of different types one on top of another. This forms the preventer stack (BOP stack), which gives both a full set of abilities and a backup. On land and on fixed platforms the stack sits on the casing head under the rig floor (the working platform of the rig). On floating rigs it sits on the seabed (see the advanced section).

BOP equipment is only the upper part of the pressure shell, the whole chain that holds the pressure of a closed well. Below it come the casing head, the casing with its cement, and the rock under the casing shoe (the bottom end of the casing). The weakest link sets the allowable pressure. While drilling, this is most often the rock under the shoe. The rock sets the maximum allowable annular surface pressure, MAASP: the highest pressure that the closed annulus may carry at the surface. A test below the shoe (the leak-off test) finds the pressure at which the rock starts to take fluid. Engineers check the strength of the casing against the same load cases (the worst loads) as for the BOP equipment (Casing design).

The annular preventer

Inside the body of the annular preventer lies a massive rubber ring, the packing element, reinforced with steel inserts. Below it is a ring-shaped piston with a conical surface. When pressure is applied under the piston, it rises and squeezes the packing element. The rubber has nowhere to go but inwards, so it closes tightly around whatever is in the bore.

It closes on anything. Drill pipe, tool joint (the thick threaded end of a drill pipe), drill collar or casing, a square or hexagonal kelly, a cable: the packing element takes the shape of the object. As a last resort it also closes an empty hole, but this wears the rubber badly.
It lets pipe pass under pressure. The crew can slowly pull the string through a closed packing element, together with its tool joints. This is called stripping. The crew lowers the closing pressure for this, so that the rubber opens in front of a tool joint and closes again behind it.
It is usually closed first. The crew does not need to worry about which pipe diameter or which tool joint is opposite the packing element.

This flexibility has a price. The working pressure of an annular preventer (the highest pressure it is built to hold) is often lower than that of the ram preventers in the same stack. It closes more slowly, because it needs more operating fluid. The packing element wears out, especially when pipe is stripped or rotated, so the crew inspects it regularly and replaces it. The closing pressure comes through a separate regulator and is chosen from the manufacturer's data. Pressure that is too high quickly destroys the rubber. Pressure that is too low does not seal the hole.

Ram preventers

Inside the body of a ram preventer, two steel rams with rubber seals move towards each other. A hydraulic piston pushes each ram. When the rams meet, they close the bore. What exactly they close depends on the shape of the rams. That is why a stack has several preventers with different rams.

SchematicWhat closes the hole, seen from above. The packing element of the annular preventer squeezes the pipe from all sides. Pipe rams have a cut-out for a pipe of one diameter. Blind rams meet along a flat face. Shear rams cut the pipe with a wedge-shaped blade. The rubber of the seals and the cutting edge are shown in orange. Not to scale.

Pipe rams: Rams with a half-round cut-out for a pipe of one particular outside diameter. They seal the annulus only if a smooth part of a pipe of that diameter is opposite them. They will not close on a tool joint, on the kelly or on a drill collar. If the pipe diameter changes, the crew changes the rams too.
Variable-bore rams: Rams with a seal that has movable steel segments, so they close on pipes within a range of diameters. They are useful when the string has pipes of different sizes. But they wear out sooner than ordinary pipe rams, and the weight that can be hung on them is smaller.
Blind rams: Rams with flat faces that close an empty hole. If the crew closes them on a pipe, they crush it but do not seal the hole.
Shear rams: Rams with blades that cut the body of the drill pipe. Blind shear rams also seal the hole after the cut. This is the last resort. As a rule, such rams do not cut a tool joint or a drill collar. So before shearing, the crew positions the string so that a smooth pipe is opposite the blades.

A ram seals at the front, on the pipe or on the second ram, and at the top, on the body. The pressure of the well reaches the cavity behind the ram and under it, and also presses the ram forward and up: the higher the pressure, the tighter the seal. Two consequences follow. First, an ordinary ram preventer holds pressure only from below. Second, closed rams can be locked with a mechanical lock, and they stay closed even if the control pressure disappears.

The crew can hang the string on closed pipe rams: it lowers the string until a tool joint sits on the rams, and the weight of the pipe passes to the stack (this is called hang-off). The crew does this before shearing a pipe, and on floating rigs before disconnecting from the wellhead. To make the stack shorter, two or three pairs of rams are placed in one body. This gives a double or a triple preventer. The bodies below the rams often have side outlets for the lines of the manifold.

To close the rams, the piston has to overcome the pressure of the well. This pressure acts on the rod of the ram, which passes from the body into the hydraulic cylinder, and pushes the rod out. The ratio of the areas of the piston and the rod is called the closing ratio.

Closing ratio of a ram preventer

K_{\text{cl}} = \frac{A_{\text{pis}}}{A_{\text{rod}}} = \left(\frac{d_{\text{pis}}}{d_{\text{rod}}}\right)^2, \qquad p_{\text{ctrl}} \ge \frac{p_{\text{well}}}{K_{\text{cl}}}

where:

$K_{\text{cl}}$ closing ratio, —
$A_{\text{pis}},\ d_{\text{pis}}$ area and diameter of the piston of the hydraulic cylinder, mm², mm
$A_{\text{rod}},\ d_{\text{rod}}$ cross-section area and diameter of the ram rod, mm², mm
$p_{\text{ctrl}}$ pressure of the operating fluid in the cylinder (control pressure), MPa
$p_{\text{well}}$ pressure in the well under the preventer, MPa

Units: any consistent units of pressure and length

Holds when

A force balance on the rod: the well pressure pushes it out with the force $p_{\text{well}} A_{\text{rod}}$ , and the piston pushes with the force $p_{\text{ctrl}} A_{\text{pis}}$ .
The friction of the seals and the force needed to compress the rubber are not included. In reality, more pressure is needed.
Shearing a pipe needs a much greater force. We estimate it from the manufacturer's data for the particular pipe.

The larger the piston is compared with the rod, the lower the control pressure that closes the preventer at the same pressure in the well. After closing, the well pressure itself helps to hold the rams.

Worked exampleWhat control pressure closes the rams

Given (assumed data)

Piston diameter of the hydraulic cylinder: 330 mm
Diameter of the ram rod: 125 mm
Pressure in the well: 35 MPa and 70 MPa
Control pressure after the regulator: 10.3 MPa (1500 psi)

Solution

Closing ratio: $K_{\text{cl}} = (330/125)^2 = 6.97$ .
Control pressure needed: $35/6.97 = 5.0$ MPa and $70/6.97 = 10.0$ MPa.
Check by forces at 70 MPa: the well pushes the rod out with a force of $70\cdot\frac{\pi}{4}\cdot 125^2 = 859$ kN, and the piston at 10.3 MPa develops $10.3\cdot\frac{\pi}{4}\cdot 330^2 = 881$ kN.

Answer: At 35 MPa in the well, a control pressure of about 5.0 MPa will close the rams. At 70 MPa the crew needs at least 10.0 MPa, which is almost all the pressure after the regulator.

What it means. At 70 MPa there is almost no margin. The force of the piston exceeds the force that pushes the rod out by only 2.6%, and the crew still has to overcome friction and compress the rubber. That is why the control unit can send the full pressure of the accumulators to the ram preventers, bypassing the regulator. To shear a pipe, the crew almost always uses this full pressure. The data in this example are assumed for illustration.

The preventer stack and its piping

The crew assembles the preventers on the casing head in a set order, and makes side outlets between them or in their bodies. Two high-pressure lines connect to the outlets. Fluid leaves the closed well through the choke line and goes to the choke manifold. The pumps send mud into the closed well through the kill line when they cannot pump through the drill string. The outlets on the stack can come from a separate part, the drilling spool.

SchematicAn example of a preventer stack of a land wellhead and its piping. From top to bottom: annular preventer, pipe rams, blind shear rams, drilling spool with outlets, lower pipe rams, casing head. The well is closed with the upper pipe rams. The mud with the inflowing fluid leaves through the outlet of the spool into the choke line and passes the choke of the manifold. Then it reaches the separator (a vessel that separates gas from mud), where the gas goes to the flare (a burner that burns it off safely). On the left is the kill line from the pumps. Not to scale.

There is no single correct layout: the positions of the rams and outlets are always a compromise. But the reasons for choosing them are general.

The annular preventer is on top. Its packing element wears out fastest, and the crew can replace it after closing the rams below it.
The outlet is below the closed element. Fluid leaves the well below the preventer that has closed it. So each preventer that the crew may use while killing the well needs its own outlet below it.
The lower rams are a backup. Designers try not to put outlets below the lowest rams, because a leak in such an outlet has nothing to shut it off. For the same reason, the crew does not circulate through the side outlets of the casing head. They are for an emergency only.
Distances between the rams. Above the lower pipe rams there must be enough room to seat a tool joint on them and to cut a smooth pipe above. If a tool joint fits between two sets of pipe rams, the crew can strip the string through while opening the rams one after the other. This is useful when the annular preventer is out of order.
Fewer connections, fewer places for leaks. Outlets in the bodies of the preventers remove the need for a spool and a pair of flanges (bolted joints). But a spool keeps the erosive flow (the flow that wears the metal away) away from the body of the preventer, and it gives room between the rams.
The position of the blind rams. Suppose the blind shear rams are above the lower pipe rams, and there is an outlet between them. Then the crew can hang the string on the lower rams, disconnect or cut the pipe above them, and close the hole with the blind rams. Through the kill line the crew still has access to the drill string: it can pump mud into it even when the equipment on the rig floor has failed. Then fluid can leave the annulus only below the lower rams. So designers cannot always leave out the outlets under them completely.

Each outlet has two valves in a row. The valve nearest to the stack is kept open, and the crew closes it only to cut off the line if something goes wrong. The crew works with the farther valve, usually hydraulically operated with remote control. The kill line also has a check valve (a valve that lets fluid pass in one direction only). It does not let fluid out of the well if the line breaks. The kill line with its valves and check valve is called the kill manifold. Russian drawings call it the “kill block”.

We can describe a stack with a code that lists the elements from the bottom up. The entry 10M – 13⅝ – RSRRA means this. The working pressure is 10,000 psi (69 MPa), and the bore (the opening through the stack) is 13⅝ inches (346 mm). From the bottom up come a single ram preventer (R), a spool (S), two ram preventers (R, R) and an annular preventer (A). This is the stack in the figure. A double ram preventer is marked Rd, and a triple one Rt. A rotating preventer (it seals around a rotating pipe), for drilling with a sealed wellhead, is marked G.

Typical stack composition by working pressure

Working pressure: 14 MPa (2000 psi)
Stack composition: an annular preventer, or a double ram preventer (pipe and blind rams); for shallow intervals

Working pressure: 21–35 MPa (3000–5000 psi)
Stack composition: an annular preventer and two ram preventers, with pipe and blind rams

Working pressure: 70–105 MPa (10,000–15,000 psi)
Stack composition: an annular preventer and three ram preventers: two with pipe rams and one with blind or shear rams

Working pressure	Stack composition
14 MPa (2000 psi)	an annular preventer, or a double ram preventer (pipe and blind rams); for shallow intervals
21–35 MPa (3000–5000 psi)	an annular preventer and two ram preventers, with pipe and blind rams
70–105 MPa (10,000–15,000 psi)	an annular preventer and three ram preventers: two with pipe rams and one with blind or shear rams

This follows the recommended practice API RP 53, in the editions that applied until 2012, when API Standard 53 replaced it. In the CIS countries (the Commonwealth of Independent States, which includes Kazakhstan), GOST 13862 sets the typical piping schemes and the main parameters. The project and the safety rules in force decide the stack for a particular well.

Working pressure

The main parameter of BOP equipment is the rated working pressure: the highest pressure at which the equipment is permitted to operate. We choose it for the worst realistic case. The well is closed and filled with gas from the highest-pressure formation up to the surface. A column of gas is light, so the pressure at the wellhead is only a little less than the formation pressure.

Highest expected wellhead pressure

p_{\text{wh}} = p_p - \rho_{\text{g}}\,g\,h

where:

$p_{\text{wh}}$ highest expected wellhead pressure (maximum anticipated surface pressure), Pa
$p_p$ highest pore pressure in the interval that will be drilled with this equipment, Pa
$\rho_{\text{g}}$ average density of the gas in the wellbore, kg/m³
$h$ vertical depth of the formation, m
$g$ acceleration due to gravity, m/s²

Units: SI; the pressures are gauge pressures

Holds when

The well is closed and filled with gas from the formation to the surface. We take the gas density with a margin on the low side.
The pore pressure is taken from the upper bound of the forecast.
If the rock under the shoe will clearly fracture first, the fracture pressure (the pressure at which the rock breaks) limits the wellhead pressure. We take the fracture pressure with a margin on the high side and subtract the pressure of the gas column up to the shoe (the same load case for the casing).

The working pressure of the BOP equipment must be no less than this value. We take the next higher standard step: “almost enough” means going up to the next step.

In other unit systems (2)

Metric units

p_{\text{wh}}\,[\text{MPa}] = p_p - 0.00981\,\rho_{\text{g}}\,[\text{g/cm}^3]\;h\,[\text{m}]

pressures in MPa, density in g/cm³, depth in m.

0.00981 MPa is the pressure of a column of fluid with a density of 1 g/cm³ and a height of 1 m.

Oilfield units

p_{\text{wh}}\,[\text{psi}] = p_p - 0.052\,\rho_{\text{g}}\,[\text{ppg}]\;h\,[\text{ft}]

pressures in psi, density in ppg (pounds per US gallon), depth in feet.

0.052 psi/ft per ppg comes from the oilfield formula for hydrostatic pressure.

Standard steps of working pressure

Designation: 2M
psi: 2,000
MPa: 13.8
Series in MPa: 14

Designation: 3M
psi: 3,000
MPa: 20.7
Series in MPa: 21

Designation: 5M
psi: 5,000
MPa: 34.5
Series in MPa: 35

Designation: 10M
psi: 10,000
MPa: 69.0
Series in MPa: 70

Designation: 15M
psi: 15,000
MPa: 103.4
Series in MPa: 105

Designation	psi	MPa	Series in MPa
2M	2,000	13.8	14
3M	3,000	20.7	21
5M	5,000	34.5	35
10M	10,000	69.0	70
15M	15,000	103.4	105

M in the designation means a thousand psi (5K and 10K are also used). The last column gives rounded values that metric standards use, including GOST 13862 (which also has a lower step of 7 MPa). Equipment for ultra-high pressures is made for 20,000 psi (138 MPa).

Worked exampleWhat working pressure the well from the kill methods lesson needs

Given (assumed data)

Well: bottom at 3350 m true vertical depth; formation pressure 43.85 MPa (found in the lesson on well kill methods from the drill pipe pressure)
Gas density (with a margin on the low side): 0.20 g/cm³
Shoe of the 244.5 mm casing: 2450 m; leak-off pressure from the test 1.68 g/cm³ (shown as the mud density that would give the same pressure at the shoe, the equivalent mud weight)
Casing: wall 11.05 mm, grade N-80: internal yield pressure 43.7 MPa

Solution

The well is closed and filled with gas: $p_{\text{wh}} = 43.85 - 0.00981\cdot 0.20\cdot 3350 = 37.3$ MPa (5407 psi).
The 35 MPa step (5000 psi) is below this value, so the next step is needed: 70 MPa (10,000 psi).
Will the rock under the shoe limit the pressure? Under a column of gas, the pressure at the shoe would be $43.85 - 0.00981\cdot 0.20\cdot 900 = 42.1$ MPa. The fracture pressure, with a margin of 0.06 g/cm³ added, is $0.00981\cdot 1.74\cdot 2450 = 41.8$ MPa. This is lower, so the rock would fracture. Then the pressure at the wellhead is $41.8 - 0.00981\cdot 0.20\cdot 2450 = 37.0$ MPa. This is almost the same, so the step does not change.
Casing: the internal yield pressure of 43.7 MPa is 1.17 times greater than 37.3 MPa.

Answer: The highest expected wellhead pressure is about 37.3 MPa. The BOP equipment, the casing head and the manifolds need a working pressure of 70 MPa.

What it means. During the kill in that lesson, the pressure in the annulus never rose above 8.1 MPa, and MAASP with mud in the annulus is about 10.6 MPa. But we choose the equipment not for the expected course of a kill. We choose it for the worst case, when the mud has been pushed out of the well and it is full of gas. Then the pressure at the wellhead is several times higher. The value is only 7% above the 35 MPa step, but that does not allow us to “round down”. The data in this example are assumed for illustration.

Every element that the well pressure can reach must have the same working pressure. These elements are the spools, flanges, valves, the choke and kill lines, and the choke manifold up to and including the chokes. One valve of a lower class turns the whole stack into equipment of that lower class.

Manifolds, the choke and the separator

The choke manifold (Russian drawings call it the “choke block”) is a set of valves, pipes and chokes through which fluid leaves the closed well. It is built with a backup. Two chokes stand in parallel branches, usually one with remote hydraulic control and the other operated by hand. If one is washed out (worn away by the flow) or blocked, the crew switches the flow to the other. Up to and including the chokes, the manifold is rated for the same working pressure as the ram preventers of the stack. After the chokes the pressure is low, and from there the flow goes to the separator, straight to the flare or to tanks. When gas flows through the manifold, the pipes vibrate strongly, so they are clamped firmly.

A choke is an adjustable restriction in the path of the flow. The narrow passage resists the flow, so pressure builds up in front of it. This pressure passes through the annulus down to the bottom of the hole. By closing the choke a little, the crew raises the pressure in the well. By opening it a little, the crew lowers the pressure (circulation at constant bottomhole pressure). An adjustable choke changes the flow area with a needle, or with a pair of discs with holes. In a fixed choke (a bean) the area is set by a replaceable sleeve.

Pressure drop across a choke for a liquid flow

\Delta p = \frac{\rho\,q^2}{2\,C_d^2\,A^2}

where:

$\Delta p$ pressure drop across the choke; if the pressure downstream of the choke is close to atmospheric, it is the annulus pressure at the wellhead, Pa
$\rho$ density of the liquid passing through the choke, kg/m³
$q$ volumetric flow rate through the choke, m³/s
$A$ flow area of the choke, m²
$C_d$ discharge coefficient, which depends on the shape of the restriction (usually 0.6–0.95), —

Units: SI

Holds when

A liquid without gas flows through the choke. The flow is turbulent, and the losses come from accelerating the jet in the restriction.
The formula does not apply to gas or to a gas–liquid mixture. Gas is compressible, and the speed in the restriction is limited by the speed of sound.
It is an order-of-magnitude estimate. We take the discharge coefficient of a real choke from the manufacturer's data.

The pressure before the choke is proportional to the density and to the square of the flow rate. This is why the pump rate is kept constant during a kill: with the choke in the same position, doubling the rate would make the pressure four times higher. It is also why the arrival of gas at the choke is noticed at once. Gas is many times lighter than mud, so with the choke in the same position the pressure before it would drop sharply. To hold the pressure, the crew closes the choke a little. When mud follows the gas again, the pressure with the choke in the same position would jump up, and the crew opens the choke a little.

Worked exampleHow far the choke is open during a kill

Given (assumed data)

Pump rate during the kill: 30 pump strokes per minute at 16.2 L per stroke, which is 8.1 L/s
Mud: 1.24 g/cm³
Pressure to hold in the annulus: 4.5 MPa
Discharge coefficient (assumed): 0.85

Solution

Jet speed in the restriction without the discharge coefficient: $\sqrt{2\,\Delta p/\rho} = \sqrt{2\cdot 4.5\cdot 10^6/1240} = 85.2$ m/s.
Flow area: $A = \dfrac{q}{C_d\sqrt{2\Delta p/\rho}} = \dfrac{0.0081}{0.85\cdot 85.2} = 112$ mm². This is like a round hole with a diameter of 12 mm.
If the rate is doubled with the choke in the same position, the pressure drop grows fourfold, to 18 MPa.

Answer: To hold 4.5 MPa at a rate of 8.1 L/s, the choke must be open to a flow area of about 112 mm². This is a hole with a diameter of about 12 mm.

What it means. During a kill the flow opening is about a centimetre across, and the jet speed is tens of metres per second. Two practical points follow. The choke is sensitive to cuttings (small pieces of rock), which can block it, and the fast flow wears it away quickly. That is why the manifold has a second choke and a bypass line, and why the crew tries to clean the mud before the kill. The data in this example are assumed for illustration. The well is the one from the kill methods lesson.

From the manifold the flow goes to the mud-gas separator. In it the flow slows down, the gas separates and goes through a vent line to the flare, and the mud drains to the shale shakers (the vibrating screens that clean the mud). The pressure in the separator is close to atmospheric, and only a liquid seal holds the gas in: a column of mud in the drain leg. Suppose more gas arrives than can leave through the vent line. Then the pressure in the separator rises and pushes the mud out of the liquid seal. The gas breaks through to the shale shakers and onto the rig. This is the capacity limit of the separator. It is why the crew limits the pump rate when gas is coming up (limits during a kill).

Worked exampleWhat pressure the liquid seal of the separator holds

Given (assumed data)

Height of the mud column in the drain leg: 3.0 m
Mud density: 1.24 g/cm³; gas-cut mud (mud with gas mixed into it) 0.90 g/cm³

Solution

Mud without gas: $0.00981\cdot 1.24\cdot 3.0 = 0.0365$ MPa, that is 36.5 kPa (5.3 psi).
If the leg holds gas-cut mud: $0.00981\cdot 0.90\cdot 3.0 = 0.0265$ MPa, that is 26.5 kPa.

Answer: A liquid seal 3 m high holds no more than 36.5 kPa in the separator, and with gas-cut mud only about 26.5 kPa.

What it means. This is more than a hundred times less than the pressure before the choke. The pressure losses in the vent line on its way to the flare must stay below this value. That is why the vent line is made wide, short and with no extra bends. The data in this example are assumed for illustration.

The BOP control unit and accumulators

Operating fluid under pressure closes the preventers and the hydraulically operated valves. The crew cannot wait until a pump delivers the required volume, and the pump may have no power at all. So the energy is stored beforehand in accumulators: bottles in which nitrogen squeezes the fluid. The bottles, the pumps with two independent sources of power, the control valves and the pressure regulators make up the BOP control unit (also called the accumulator unit). It stands away from the wellhead. The crew operates the preventers both from it and from the driller's panel (the control panel at the driller's post).

The crew fills the bottle with nitrogen beforehand, to an initial pressure (the precharge). Pumps push fluid into the bottle and compress the gas to the working pressure of the system.
When a control valve is opened, the compressed gas pushes the fluid to the preventer. The pumps start automatically and replace what was used.
Regulators lower the pressure for the different devices. One pressure goes to the ram preventers and valves. The annular preventer gets its own pressure, usually lower and adjustable.
Each preventer has two lines, one to close it and one to open it. The positions of the control valves and the pressures can be seen on the panels.

The gas law decides how much fluid a bottle gives. While the gas pressure is above the minimum allowable, the fluid can be used. The fluid left in the bottle at a lower pressure is no longer enough to close a preventer reliably.

Usable fluid volume of an accumulator

V_{\text{use}} = V_{\text{bottle}}\,p_0\left(\frac{1}{p_{\min}} - \frac{1}{p_{\text{work}}}\right)

where:

$V_{\text{use}}$ usable volume of fluid that the bottle gives while the pressure falls from the working pressure to the minimum, L
$V_{\text{bottle}}$ volume of the gas space of the bottle with no fluid in it, L
$p_0$ initial pressure of the nitrogen in the bottle with no fluid (absolute), MPa
$p_{\text{work}}$ working pressure of the charged system (absolute), MPa
$p_{\min}$ lowest pressure at which the fluid is still counted as usable (absolute), MPa

Units: any consistent units of pressure and volume; the pressures are absolute

Holds when

Nitrogen is an ideal gas (it follows the simple gas law exactly), and the temperature is constant: $p_0 V_{\text{bottle}} = p\,(V_{\text{bottle}} - V_{\text{L}})$ , where $V_{\text{L}}$ is the volume of fluid in the bottle.
The discharge is slow. In a fast discharge the gas cools, and the usable volume is noticeably smaller (see the advanced section).
The pressures are absolute: add the atmospheric pressure to the gauge reading.

Suppose the initial nitrogen pressure is three times lower than the working pressure, and the minimum pressure is a little above the initial one. Then about half of the volume of the bottle is usable. To find the number of bottles, divide the required volume of fluid by the usable volume of one bottle.

CalculatedPressure in a bottle of 40 L against the amount of fluid pumped in (nitrogen compressed at constant temperature, initial pressure 7 MPa). Between the working pressure of 21 MPa and the minimum of 8.4 MPa, the bottle gives about 20 L, which is half of its volume.

Worked exampleUsable volume of a bottle and the number of bottles

Given (assumed data)

Bottle: 40 L; initial nitrogen pressure 7.0 MPa
System pressures (gauge): working 21.0 MPa, minimum 8.4 MPa
Fluid volume to close (assumed): annular preventer 70 L; three ram preventers at 22 L each; two hydraulic valves at 2 L each
Requirement of the example: a safety factor of 1.5 on the closing volume of all the devices that use fluid, with the pumps not working

Solution

Absolute pressures: $p_0 = 7.101$ MPa, $p_{\text{work}} = 21.101$ MPa, $p_{\min} = 8.501$ MPa.
Fluid in the bottle at the working pressure: $40\cdot(1 - 7.101/21.101) = 26.54$ L. At the minimum pressure: $40\cdot(1 - 7.101/8.501) = 6.59$ L. Usable volume: 19.95 L, which is 50% of the volume of the bottle.
Required volume: $70 + 3\cdot 22 + 2\cdot 2 = 140$ L. With the factor of 1.5 it is 210 L. Number of bottles: $210/19.95 = 10.5$ , that is 11.

Answer: A bottle gives 19.95 L of usable fluid, about half of its volume. The isothermal calculation needs 11 bottles.

What it means. The calculation shows the physics, not the method for sizing a real unit. Engineers size the accumulators of a real unit with the standard in force. The standard sets which operations must be done with the pumps not working, what pressure must remain, and how to calculate the gas. The method includes the cooling of the gas in a fast discharge and the fact that nitrogen at high pressure does not behave like an ideal gas. Such corrections reduce the usable volume. The data in this example are assumed for illustration.

Standards also limit the closing time. For example, API Standard 53 (the 2012 and 2018 editions) says that a ram preventer in a stack on land must close in no more than 30 seconds. An annular preventer must close in 30 seconds if its bore is smaller than 18¾ inches, and in 45 seconds if the bore is 18¾ inches or more. For a stack on the seabed (a subsea stack) the limits are 45 seconds for ram preventers and 60 seconds for annular preventers. National rules and company standards may be stricter.

Shutting off the drill string from the inside

Preventers close the annulus, but formation fluid can also go up the drill string. While drilling, the string is connected to the pumps, and the crew shuts it with valves under the swivel (the part that lets the string turn while mud is pumped in) or the top drive (the motor that turns the string). During trips (pulling the string out of the hole and running it back in), the top of the string is open. For this case, the crew keeps separate devices on the rig floor.

Kelly and top drive ball valves (kelly cock): Full-opening ball valves (valves with a turning ball that has a hole through it, as wide as the pipe) above and below the kelly. With a top drive, the valves are built into it. They shut the string and protect the rotary hose and the swivel from the pressure.
Ball valve on the rig floor (full-opening safety valve): A full-opening ball valve. It lies ready in the open position, together with crossover subs (short adapters) for all the threads in use. Suppose the well starts to flow through the pipe during a trip. The crew screws the open valve onto the top pipe and closes it. The flow passes freely through an open valve, so the crew can screw it on. A closed valve or a check valve would not let the crew screw it on against the flow.
Check valve for stripping in (inside BOP): A valve that lets the flow pass only downward. The crew puts it above a closed ball valve if the string has to be run into the well under pressure. The crew then opens the ball valve, and the check valve holds the pressure from below and still lets the crew pump mud.
Float valve above the bit: A valve in the bottom hole assembly (the lowest part of the string). It does not let the mud flow back into the pipes when the crew adds a pipe. During a kick it hides the pressure in the drill pipe: the gauge shows zero. The crew finds the pressure below the valve by pumping mud in carefully until the valve opens (pressures after shut-in).

The diverter: when the well must not be closed

At shallow depth, while only the conductor has been run, closing the well on a kick is dangerous. The rock under a shallow shoe is weak, and the pressure of a closed well will fracture it. The gas will break out to the surface outside the casing. A crater will form around the wellhead (the ground is blown out), and at sea the stability of the rig itself will be at risk. So the crew does not try to stop the inflow. The crew sends it to the side instead.

A diverter is a low-pressure preventer, usually of the annular type, with large-diameter vent lines. It closes the way up to the rig floor and at the same time opens the valve of a vent line. The flow goes through this line to a safe place, with the wind direction in mind. The pressure is low, only a few megapascals, but the flow rates are huge, and the flow carries sand. So the vent lines are made straight, wide and with no restrictions, and they are firmly fixed. A diverter does not hold the well and does not replace BOP equipment. It only buys time to move the flow away from people.

Worked exampleWhy the well must not be closed on the conductor

Given (assumed data)

Conductor shoe: 120 m; fracture pressure below it 1.40 g/cm³
Gas formation: 480 m vertical depth, normal pressure of 1.03 g/cm³
Gas density at this pressure: about 0.04 g/cm³

Solution

Pressure in the gas formation: $0.00981\cdot 1.03\cdot 480 = 4.85$ MPa.
If the well is closed and gas has already pushed the mud out of it, the pressure at the shoe will be $4.85 - 0.00981\cdot 0.04\cdot 360 = 4.71$ MPa.
Fracture pressure below the shoe: $0.00981\cdot 1.40\cdot 120 = 1.65$ MPa, which is 2.9 times lower.

Answer: The pressure at the shoe of a closed well (4.71 MPa) would be almost three times the fracture pressure (1.65 MPa). The well must not be closed, and the diverter sends the flow away.

What it means. A formation with a perfectly normal pressure is dangerous simply because the shoe is much shallower. The gas pressure reaches the weak rock almost with no loss. At the depth of the shoe, this is an equivalent mud weight of 4.0 g/cm³, which is more than the overburden pressure (the pressure from the weight of all the rock above). The main protection against shallow gas is not equipment. It is to predict the gas before drilling and to choose the well location accordingly. The data in this example are assumed for illustration.

Checks and pressure tests

BOP equipment sits idle most of the time, and the only way to know that it is in order is to test it. There are two kinds of test. A function test closes and opens the preventers and valves, one after another, from different control panels, and measures the time and the fluid volume. A pressure test puts pressure on a closed element and watches whether it holds.

The crew applies the pressure from below, as it would come from the well, because rams hold only in this direction. To avoid loading the casing and the rock, the crew installs a test plug in the casing head.
The crew tests each element first at low pressure and then at high pressure. A seal that holds a high pressure may leak at a low pressure. The pressure itself presses the rubber tight, and at a low pressure there is no such squeeze.
The high test pressure depends on the working pressure of the equipment and on the highest expected wellhead pressure. The crew usually tests an annular preventer at a pressure below its working pressure, to save the packing element.
The crew tests everything that the pressure can reach: the choke and kill lines, the manifold, and the ball valves and check valves of the drill string.
The crew tests after installation and after the replacement or repair of any element, repeats the tests at set intervals, and records the results.

Example of test requirements

What: Low-pressure test
Requirement: 1.7–2.4 MPa (250–350 psi)

What: Holding time under pressure
Requirement: at least 5 minutes after the pressure stabilises

What: Pressure test
Requirement: at least once every 21 days

What: Function test
Requirement: as a rule, at least once every 7 days

What: Annular preventer
Requirement: not more than 70% of its working pressure

What	Requirement
Low-pressure test	1.7–2.4 MPa (250–350 psi)
Holding time under pressure	at least 5 minutes after the pressure stabilises
Pressure test	at least once every 21 days
Function test	as a rule, at least once every 7 days
Annular preventer	not more than 70% of its working pressure

From API Standard 53, the 2012 and 2018 editions; given as a guide. The requirements of the project, the national safety rules and the company standards apply, and they may differ.

Equipment is only half of the job. The drilling crew regularly holds drills (practice alarms) and rehearses what to do at the first signs of a kick. A preventer in perfect order is useless if the inflow is noticed late (why it is important to notice a kick early).

Terms and symbols

BOP: Blowout preventer equipment: preventers, manifolds and the control system that seal the wellhead and control the pressure.
Preventer stack (BOP stack): Preventers placed one on top of another on the casing head.
Annular preventer: A preventer with a ring-shaped rubber packing element that closes on a pipe of any shape and size.
Ram preventer: A preventer with two opposed rams: pipe rams, blind rams or shear rams.
Drilling spool: A part of the stack with side outlets for the choke line and the kill line.
Choke line and kill line: High-pressure lines at the stack: the choke line goes to the choke manifold, and the kill line comes from the pumps.
Choke: An adjustable restriction that builds up pressure in the closed well while fluid is let out.
Rated working pressure: The highest pressure at which the equipment is permitted to operate.
Accumulator: A bottle in which the operating fluid is stored under the pressure of compressed nitrogen.
Closing ratio, $K_{\text{cl}}$: The ratio of the area of the hydraulic cylinder piston to the cross-section area of the ram rod.
Diverter: A low-pressure preventer with large-diameter vent lines: it diverts the flow without closing the well.

Common mistakes and misconceptions

Wrong

“The annular preventer closes on anything, so ram preventers are not needed.”

In fact

Its working pressure is often lower, its packing element wears, and it is slower. It can neither hold the weight of the string nor cut a pipe. Ram preventers give the high pressure, the backup and these abilities.

Wrong

“Pipe rams will close the well, whatever pipe is in the wellhead.”

In fact

Only if a smooth pipe of the diameter they were made for is opposite them. They will not close on a tool joint, on the kelly or on a drill collar. Variable-bore rams work only within their own range.

Wrong

“Blind rams will close the hole as a last resort, even with a pipe in it.”

In fact

Blind rams crush the pipe but do not seal the hole. Only shear rams can cut a pipe, and even then only the pipe body, not the tool joint.

Wrong

“The preventer is rated at 70 MPa, so the well can be kept closed at 70 MPa.”

In fact

The weakest link of the pressure shell sets the limit: the rock under the shoe, the casing, the casing head, or any valve of the manifold. While drilling, it is usually the rock under the shoe.

Wrong

“A bottle of 40 L gives 40 L of fluid.”

In fact

Compressed nitrogen takes part of the volume, and fluid at a pressure below the minimum is useless. About half of the volume is usable by the isothermal calculation, and less in a fast discharge.

In depth: advanced detail

Fast discharge: why the usable volume is smaller

The isothermal calculation assumes that the gas in the bottle has time to take heat from the walls, so its temperature does not change. But preventers close in seconds or tens of seconds. The gas expands fast, does work (it pushes the fluid out) and cools. Cold gas at the same volume has a lower pressure. So by the time the pressure falls to the minimum, the bottle has given less fluid. The limiting case is expansion with no heat exchange at all, which is called adiabatic.

Adiabatic expansion of the gas in the bottle

p\,V^{\gamma} = \text{const}, \qquad V_2 = V_1\left(\frac{p_1}{p_2}\right)^{1/\gamma}

where:

$p_1,\ V_1$ absolute pressure and volume of the gas in the charged bottle, MPa, L
$p_2,\ V_2$ absolute pressure and volume of the gas after the discharge, MPa, L
$\gamma$ adiabatic index; for nitrogen at moderate pressures about 1.4, —

Units: any consistent units; the pressures are absolute

Holds when

An ideal gas, expanding with no heat exchange with the walls.
The bottle is charged slowly, at constant temperature (isothermally).
At high pressures nitrogen differs noticeably from an ideal gas, and a precise calculation uses the equation of state of a real gas.

The volume of fluid that the bottle gives equals the gain in the gas volume $V_2 - V_1$ . In an isothermal expansion the exponent of the pressure ratio equals one. In an adiabatic expansion it is less than one, and the gas expands less.

Worked exampleThe same bottle in a fast discharge

Given (assumed data)

Bottle and pressures: as in the example in the main text: 40 L; 7.0 / 21.0 / 8.4 MPa (gauge)
Adiabatic index of nitrogen: 1.4

Solution

Gas volume in the charged bottle: $40\cdot 7.101/21.101 = 13.46$ L.
After adiabatic expansion to the minimum pressure: $13.46\cdot(21.101/8.501)^{1/1.4} = 25.77$ L.
Usable volume: $25.77 - 13.46 = 12.3$ L, which is 62% of the isothermal value (20.0 L). For the same 210 L the crew would need 18 bottles instead of 11.

Answer: In a fast discharge a bottle gives about 12.3 L instead of 20.0 L.

What it means. A real discharge lies between the two limiting cases: the faster the fluid is used, the closer it is to adiabatic. So engineers use the adiabatic calculation for systems that must work in seconds, such as the emergency closing of shear rams. At high pressures they also use the equation of state of a real gas (a formula for how real nitrogen behaves). The isothermal estimate of “half a bottle” applies to a slow use of fluid, and it works as a guide. The data in this example are assumed for illustration.

Subsea BOP equipment in outline

On floating drilling rigs the preventer stack stands on the wellhead at the seabed. A marine drilling riser, a large-diameter pipe, connects the stack to the rig (Offshore and subsea drilling). The purpose of the equipment is the same. But the working conditions change almost everything else.

A stack of two parts. The upper part, with the annular preventer and the control equipment, can be disconnected from the lower one. Then the rig can move away and leave the well closed with rams. Before this, the crew hangs the string on the rams and disconnects it above them. In an emergency, the crew cuts the string.
More preventers. The stack is hard to reach, so there is more backup. There are usually two annular preventers and four to six ram preventers, and among the rams there are always shear rams.
Long choke and kill lines. They run along the riser for the full depth of the sea, and their friction pressure losses add to the pressure in the well. The crew measures these losses beforehand and takes them into account when killing the well.
Control. The signal and the operating fluid must reach the seabed. So at great sea depths the control systems are electro-hydraulic (electric signals operate the hydraulic valves), with two independent control pods (blocks) on the stack. Part of the accumulators is put right on the stack.
Water pressure. At the seabed a column of sea water presses on the equipment. The control fluid is released against this pressure, and the initial nitrogen pressure in subsea bottles is raised by the same amount. The usable volume of a bottle then falls, and nitrogen behaves much less like an ideal gas.
Emergency systems. If the link with the rig is lost, or the rig drifts off its position, the shear rams must close automatically. The system also allows control from a remotely operated underwater vehicle (ROV).

Connections to other topics

Well control: primary barrier and kick indicators — primary and secondary well control, and the signs of a kick.
Well kill methods — how the crew kills the well through the choke and the manifold, and what pressures arise.
Fracture gradient and leak-off testing — the rock under the shoe as the weakest link of the pressure shell, and MAASP.
Casing design — design of the casing for the same case: a closed well full of gas.
Casing: purpose, types, properties and standards — the casing and the casing head on which the preventer stack stands.
How a well is drilled: the process and the people involved — when in the construction of a well the BOP equipment is installed and pressure-tested.
Wellheads and running casing — casing heads and wellhead equipment.
Offshore and subsea drilling — the subsea wellhead, the riser and the subsea preventer stack.

Check yourself

1
During a kick, a kelly of square section is in the wellhead. Which preventer will seal the annulus?
1. A.Pipe rams
2. B.None: the crew must pull the string first
3. C.Blind rams
4. D.Annular preventer
Show the answer
Correct answer: D. Annular preventer
The rubber packing element of the annular preventer closes around an object of any shape. Pipe rams are made for a round pipe of one diameter, and blind rams for an empty hole.
2
The highest-pressure formation of the interval is at 3000 m, with a pressure of 1.45 g/cm³. The gas density is assumed to be 0.2 g/cm³. What working pressure of the BOP equipment is needed?
Show the answer
Formation pressure: $0.00981\cdot 1.45\cdot 3000 \approx 42.7$ MPa. The well is closed and full of gas: $42.7 - 0.00981\cdot 0.2\cdot 3000 \approx 36.8$ MPa. This is more than 35 MPa, so the next step is needed: 70 MPa (10,000 psi). It is needed for the whole piping, not only for the preventers.
3
Why do designers try not to put working outlets below the lowest rams of the stack?
1. A.Pressure cannot be measured through the lower outlets
2. B.The temperature there is too high
3. C.Outlets get in the way of running the casing
4. D.A leak in an outlet or a line below the lowest rams cannot be shut off: there is no closing element under them
Show the answer
Correct answer: D. A leak in an outlet or a line below the lowest rams cannot be shut off: there is no closing element under them
Every outlet and every line is a possible place for a leak. If it is above some rams, the crew can close them and cut off the damaged part. Below the lowest rams there is nothing to cut it off with. So the lowest rams are kept as a backup, and the crew does not circulate through the outlets of the casing head.
4
An accumulator bottle of 50 L is charged with nitrogen to 7.0 MPa. The working pressure of the system is 21.0 MPa and the minimum is 8.4 MPa (gauge). Find the usable volume of fluid by the isothermal calculation.
Show the answer
Absolute pressures: 7.101, 21.101 and 8.501 MPa. $V_{\text{use}} = 50\cdot 7.101\cdot(1/8.501 - 1/21.101) \approx 24.9$ L, which is half of the volume of the bottle. In a fast discharge the gas cools, and in practice the bottle gives noticeably less.
5
Why does the crew not close the well on a kick while drilling for the surface casing, when only the conductor has been run?
1. A.The rock under a shallow shoe will not withstand the pressure of a closed well: the gas will come to the surface outside the casing
2. B.Shallow gas is not dangerous
3. C.Preventers are not made for such a diameter
4. D.Closing takes too much time
Show the answer
Correct answer: A. The rock under a shallow shoe will not withstand the pressure of a closed well: the gas will come to the surface outside the casing
The gas pressure reaches the shoe almost with no loss, and the fracture pressure there is low because the depth is small. The rock will fracture, and the gas will go to the surface outside the casing. So a diverter sends the flow to a safe place.
6
The closing ratio of a ram preventer is 7. What control pressure is needed to close the rams at 35 MPa in the well, and why is more needed in practice?
Show the answer
From the force balance on the rod: $35/7 = 5$ MPa. The formula does not include the friction of the seals and the force needed to compress the rubber of the rams, so the real pressure is higher. Shearing a pipe needs a far greater force, so the crew sends the full pressure of the accumulators to the shear rams.

Updated: 28 October 2026