Offshore and subsea drilling

Quick refresher

Rigs that rest on the seabed (an island, a barge, a platform, a jack-up) drill with the preventers above the water, almost as on land. Floating rigs (semi-submersibles, which float on submerged pontoons, and drillships) drill through a wellhead and a preventer stack that stand on the seabed. A riser joins them to the rig. The rig can disconnect and move away, and it leaves the well closed.
A subsea well starts without a riser. The conductor (the first and widest string) is run into a drilled hole or jetted in, that is, washed into the soil with a jet of water. We drill the top interval with sea water and dump the cuttings (pieces of rock) on the seabed. After the surface casing (the next string) with the high-pressure housing is set, we run the preventers and the riser, and from then on we hang all casing strings in this housing.
Tensioners (cylinders on the rig that pull the riser up) hold the riser in tension. The least tension is the weight of the structure in water plus the “extra” weight of the mud, $A_{\text{bore}}(p_m - p_{sw})$ . The buoyancy modules (foam shells on the riser) take off most of the weight of the steel, but not that of the mud.
The riser margin is the extra mud density that keeps the well under control after a disconnect, when sea water replaces the mud above the seabed. In deep water the window between the pore pressure (the pressure of the fluid in the rock) and the fracture pressure (the pressure at which the rock cracks) is narrow, and the margin is often out of reach. Then the preventers hold the well when the riser is disconnected.
To kill the well (stop a kick, an inflow of formation fluid, by pumping in heavy mud) through the subsea stack, we send the flow up the long choke line, the pipe that carries the returns from the stack to the choke. The friction losses in this line add to the pressure in the well. When the pump is started, we subtract these losses from the pressure at the choke.
In the northern Caspian at Kashagan the sea is 3–4 m deep and covered with ice for about five months a year. Wells are drilled from barges and artificial islands with the wellhead above the water. In the state nature reserve zone, work is limited by season, by discharges, by flaring (burning off gas) and by drilling waste. Wells and islands are abandoned under special requirements.

Key relationships

\Delta\rho_{\text{rm}} = \dfrac{\rho_{\text{p}}\,(h_a + h_w) - \rho_{sw}\,h_w}{H - h_a - h_w}

riser margin; the equivalent mud weights (pressures written as the density of a mud column) are measured from the rotary table

T_{\min} = w_s\,h_w + A_{\text{bore}}\,(p_m - p_{sw})

least tension at the top of the riser

\rho_{\text{below seabed}} = \rho_{sw} + \dfrac{\Delta p_{\text{excess}}}{0.00981\,z}

the density that holds the formation when there is a column of sea water above the seabed

Common pitfalls

Comparing the mud density with equivalent mud weights that are not measured from the rotary table, for example from the seabed. Under 1200 m of water the pore pressure of the formation in the example of this lesson “weighs” about 2.1 g/cm³ from the seabed, and 1.17 from the rotary table.
Thinking that the buoyancy modules take the load of the mud too. The extra weight of the mud stays on the tensioners and grows with its density.
Keeping the pressure at the choke the same when the pump is started, as on land. The pressure in the well will rise by the losses in the choke line.
Thinking that shallow water makes work easier for a floating rig. The same drift gives a larger tilt of the riser the smaller the depth is.

After this lesson you can

compare offshore drilling rigs (an artificial island, a drilling barge, a platform, a jack-up, a semi-submersible and a drillship) by sea depth and conditions, and say where each has its wellhead and its preventers
describe step by step how a subsea well is built: the conductor (the first pipe of the well, including jetting it in, that is, washing it into the seabed with a jet of water), drilling without a riser, the high-pressure wellhead housing, running the preventers and the riser, and the hangers (supports) of the casing strings in the housing
explain how a riser is built and calculate its tension, taking into account the mud, the buoyancy modules and the failure of a tensioner
calculate the riser margin and show why it is often out of reach in deep water, and estimate the friction losses in the choke line while killing the well
name the hazards of the shallow section and the ways to drill the upper intervals
describe the completion, suspension and abandonment of a subsea well, and the requirements of the rules of Kazakhstan for offshore wells and for work in the nature reserve zone of the northern Caspian

Offshore drilling rigs and where the wellhead stands

We drill at sea in the same way as on land. A string of pipes turns the bit, mud carries the cuttings out, and casing strings line the hole (see How a well is drilled: the process and the people involved). What changes is what the rig stands on. That changes where the wellhead and the blowout preventer (BOP) equipment end up: above the water, as on land, or on the seabed.

Rigs fall into two families. Rigs that rest on the seabed are an artificial island, a drilling barge in shallow water, a fixed platform and a jack-up rig. They do not move against the seabed, and they carry an ordinary preventer stack above the water. Floating rigs are a semi-submersible and a drillship. They rock on the waves and drift. So the wellhead and the preventers stand on the seabed, and the marine drilling riser joins them to the rig. The riser can be disconnected, and the rig can move away. The preventers keep the well closed.

SchematicOffshore drilling rigs from shallow water to deep water (diagram, not to scale). Rigs that rest on the seabed have the preventers above the water. Floating rigs have them on the seabed, and a riser joins them to the rig.

Offshore drilling rigs (approximate, 2020s)

Rig: Artificial island
How it is held: a fill on the seabed; protects against ice and waves
Sea depth: a few metres
Wellhead and BOP: above the water, as on land

Rig: Drilling barge
How it is held: sunk until it rests on the seabed, or held by anchors
Sea depth: a few metres
Wellhead and BOP: above the water

Rig: Fixed platform
How it is held: a steel lattice support on piles, or a concrete gravity base
Sea depth: up to hundreds of metres
Wellhead and BOP: above the water; tens of wells are drilled from one platform

Rig: Jack-up rig
How it is held: the hull is raised above the water on legs that stand on the seabed
Sea depth: usually up to 120 m, some up to 150 m
Wellhead and BOP: above the water; the casing strings are held by hangers at the seabed (a mudline suspension system)

Rig: Semi-submersible rig
How it is held: floats on submerged pontoons; anchors or dynamic positioning
Sea depth: from tens of metres to 3 km
Wellhead and BOP: on the seabed; the link is a riser

Rig: Drillship
How it is held: a ship with the rig over a moonpool (an opening in the hull); usually dynamic positioning
Sea depth: hundreds of metres to 3.6 km
Wellhead and BOP: on the seabed; the link is a riser

Rig	How it is held	Sea depth	Wellhead and BOP
Artificial island	a fill on the seabed; protects against ice and waves	a few metres	above the water, as on land
Drilling barge	sunk until it rests on the seabed, or held by anchors	a few metres	above the water
Fixed platform	a steel lattice support on piles, or a concrete gravity base	up to hundreds of metres	above the water; tens of wells are drilled from one platform
Jack-up rig	the hull is raised above the water on legs that stand on the seabed	usually up to 120 m, some up to 150 m	above the water; the casing strings are held by hangers at the seabed (a mudline suspension system)
Semi-submersible rig	floats on submerged pontoons; anchors or dynamic positioning	from tens of metres to 3 km	on the seabed; the link is a riser
Drillship	a ship with the rig over a moonpool (an opening in the hull); usually dynamic positioning	hundreds of metres to 3.6 km	on the seabed; the link is a riser

The depths are a guide from the rig data sheets of the 2020s. The deepest drillships are rated for 12,000 feet (3.6 km) of water, and most jack-ups for up to 400 feet (120 m). Besides the depth, the choice depends on waves, ice, the soil, the purpose of the well (exploration or production), the distance from the shore and the rental rate.

A floating rig is held over the well in two ways. A mooring system (anchors and lines) usually has 8–12 mooring lines of chain and steel wire rope, and in deep water also synthetic ropes. Anchor-handling tugs lay the anchors and pull them tight. Before that, the crew checks that there are no pipelines on the seabed. With dynamic positioning (DP) a computer keeps the rig on its point all the time with thrusters (propellers on the hull). It uses satellite navigation and acoustic beacons on the seabed. The systems have backups, so that the failure of one engine or generator does not move the rig. The deeper the sea, the longer and heavier the mooring lines are. So in deep water dynamic positioning is the most common.

A jack-up rig is towed to the site afloat. The crew lowers the legs to the seabed and then raises the hull up the legs above the water. Before work, the legs are preloaded: the rig takes on ballast (water pumped into tanks to add weight), so that the soil under the legs takes a load larger than the working load in advance. The most dangerous accident here is punch-through: a strong layer above weak clay suddenly breaks, and the leg sinks metres into the soil. So engineers study the soil under the legs in site surveys as carefully as the place of the well.

The preventers of a jack-up stand above the water, on a casing string that is extended from the seabed up to the rig. But the rig leaves after drilling, and the casing strings must stay at the seabed. So we hang them in a mudline suspension system (the mudline is the seabed). The hangers are run with the casing strings and landed one in another at the level of the seabed. Above them, the strings are extended to the rig while we drill. When drilling is finished, these extensions are disconnected and pulled up, and the well is suspended (closed for a while) at the seabed. Later one of three things happens to the well. It is connected to a platform that is built above it, or it is completed with a subsea tree (the valve assembly on the wellhead), or it is abandoned.

How a subsea well is built

A subsea well is built “from the base up”. First a base is made on the seabed: the conductor with a low-pressure wellhead housing. Then the high-pressure wellhead housing is set in it, and the preventers and the riser on top of that. Only after this do we drill with the mud returning to the rig. While there is no riser, the mud and the cuttings come out of the well straight onto the seabed. Below is a teaching well under 1200 m of water. Its data are used in all the examples of the lesson.

Casing programme of the teaching subsea well (assumed)

String: Conductor 914.4 mm (36″)
Hole: — (jetted in)
Shoe (the lower end of the string) below the seabed: 75 m
How the interval is drilled: the soil is washed away by a jet; there is no drilling

String: Surface casing 508 mm (20″) with a 476 mm (18¾″) housing
Hole: 660.4 mm (26″)
Shoe (the lower end of the string) below the seabed: 700 m
How the interval is drilled: without a riser, with sea water and viscous sweeps; the cuttings go to the seabed

String: Intermediate 339.7 mm (13⅜″)
Hole: 444.5 mm (17½″)
Shoe (the lower end of the string) below the seabed: 2000 m
How the interval is drilled: through the preventers and the riser; the mud returns to the rig

String: Production 244.5 mm (9⅝″)
Hole: 311.1 mm (12¼″)
Shoe (the lower end of the string) below the seabed: 3300 m
How the interval is drilled: the same

String: Liner 177.8 mm (7″)
Hole: 215.9 mm (8½″)
Shoe (the lower end of the string) below the seabed: 3800 m
How the interval is drilled: the same; hung in the previous string

String	Hole	Shoe (the lower end of the string) below the seabed	How the interval is drilled
Conductor 914.4 mm (36″)	— (jetted in)	75 m	the soil is washed away by a jet; there is no drilling
Surface casing 508 mm (20″) with a 476 mm (18¾″) housing	660.4 mm (26″)	700 m	without a riser, with sea water and viscous sweeps; the cuttings go to the seabed
Intermediate 339.7 mm (13⅜″)	444.5 mm (17½″)	2000 m	through the preventers and the riser; the mud returns to the rig
Production 244.5 mm (9⅝″)	311.1 mm (12¼″)	3300 m	the same
Liner 177.8 mm (7″)	215.9 mm (8½″)	3800 m	the same; hung in the previous string

The rotary table is 25 m above sea level, and the sea is 1200 m deep. The depth from the rotary table is 25 + 1200 + the depth below the seabed. The combinations of casing strings and bits are the usual series in inches (strings by purpose). In practice there are often more strings in deep water, because the pressure window is narrow.

Order of construction

1
Site and seabed
We study the site in advance: bathymetry (a map of the sea depth), a high-resolution seismic survey of the shallow rocks, and soil samples and probing tests. The rig is placed on the point, and a remotely operated underwater vehicle (ROV) inspects the seabed before the equipment is run. At medium depths the tools and equipment are guided to the wellhead along tight guide lines fixed to a guide base on the seabed. In deep water the crew does without lines and steers by the video cameras of the vehicle.
2
Conductor
The first string is a conductor of large diameter with a low-pressure wellhead housing at its top. We either run it into a drilled hole and cement it up to the seabed or, in soft clays, we jet it in. An assembly with a bit hangs on the drill string inside the pipe. A jet of water from its nozzles washes away the soil at the shoe, and the conductor sinks under its own weight and part of the weight of the assembly. Then we give the soil time to “set” around the pipe, and only after that disconnect the running tool. The conductor carries the weight of the next strings, of the wellhead equipment and of the preventers, and the bending load from the riser. So we calculate its length from the strength of the soil (see the advanced section).
3
Drilling without a riser
The hole for the surface casing is drilled through the low-pressure housing, with no riser and no preventers. The crew circulates sea water with viscous sweeps (small batches of thick fluid that sweep the cuttings out), and the mud and the cuttings come out of the wellhead onto the seabed. As protection against shallow sands with water or gas under pressure, we keep a weighted mud (a heavier mud) ready. We also pump it “to waste”, so that it goes to the seabed (pump and dump). There are also systems that pump the mud coming out of the wellhead from the seabed up to the rig.
4
Surface casing and the high-pressure housing
The surface casing is run with a high-pressure wellhead housing welded to its top. This is a massive body with a bore of 476 mm (18¾″). The housing lands and latches in the low-pressure housing. We cement the surface casing through an inner string, drill pipe that we run inside it. We raise the cement to the seabed, and the camera of the vehicle checks that the cement comes out.
5
Preventers and riser
The preventer stack is run on the riser in one trip. A hydraulic connector at the bottom of the stack latches onto the housing. Then we tension the riser, connect the lines, check that the preventers work and test them with pressure. From here we drill as on land: the mud rises through the annulus (the space around the string) and the riser to the rig.
6
The next strings
Each next string ends at the top with a hanger. We run the string through the riser and the preventers and land the hanger in the high-pressure housing, so the hangers lie one on top of another. We cement the string through the running tool, and in the same trip we set the seal (pack-off) between the hanger and the housing and test it with pressure. While drilling goes on, a replaceable protective sleeve (a wear bushing) covers the landing surfaces of the housing. A liner is hung in the previous string, not in the housing.
7
Tests
We pressure-test each string. After the bit drills out of the shoe, we run a leak-off test (it finds the pressure at which the rock below the shoe starts to take mud; how it is run and read). It decides which mud we can use to drill the next interval.

SchematicThe first stages of a subsea well (diagram, not to scale). 1: the conductor with the low-pressure housing is jetted in. 2: the hole for the surface casing is drilled without a riser, and the cuttings come out onto the seabed. 3: the surface casing with the high-pressure housing is cemented up to the seabed. 4: the preventer stack stands on the housing, and the mud returns to the rig through the riser.

A subsea wellhead is the extreme case of a compact casing head (the wellhead stack). One housing takes the hangers of all the strings. They are landed through the preventers without taking the stack off, and a string of an unplanned size will not fit into it. So we choose the casing programme of a subsea well in advance and with a margin. If the pressures turn out worse than forecast, the extra string will have to be a liner.

SchematicA subsea wellhead in section (diagram, not to scale): the low-pressure housing on the conductor, and in it the high-pressure housing on the surface casing. In its bore are the hangers of the intermediate and production strings with their seals. The connector of the preventers latches on top of the housing, and later the connector of the tree (the valve assembly that controls the producing well).

The riser: the link between the rig and the well

The riser is a string of large-diameter pipe (usually 533 mm, 21″). It is made of sections about 23–27 m long, joined by flanges or couplings. The mud rises through it to the rig. We run tools and casing strings through it. Outside it, along its length, run the choke and kill lines (pipes for taking fluid out of a closed well and for pumping mud into it), a booster line that pumps mud into the bottom of the riser, and the control lines of the stack.

Lower marine riser package (LMRP): the upper, detachable part of the subsea stack: the annular preventers, a hydraulic connector and the control pods. It is lifted with the riser, while the ram preventers stay on the wellhead and keep the well closed (subsea BOP equipment).
Flex joints: at the bottom and at the top of the riser: they let it tilt from the vertical by a few degrees without bending the pipes at the connector.
Buoyancy modules: shells of syntactic foam (a foam material with hollow glass microspheres) on the sections. They take off most of the weight of the riser in water. With time they take up water and lose part of their lift.
Telescopic joint: under the drill floor: the inner pipe slides in the outer one, so the riser does not feel the up-and-down heave of the rig and the tide.
Riser tensioners: hydro-pneumatic cylinders (worked by oil and compressed gas) that pull the outer pipe of the telescopic joint upward with an almost constant force, through wire ropes or directly.
Diverter under the rotary table: sends the gas that has entered the riser above the closed preventers off to the side (diverter).
Heave compensator: in the hoisting system or in the drawworks (the winch that raises and lowers the string): it separates the drill string from the heave, so that the weight on the bit does not change even though the rig rises and falls by metres.

A riser cannot stand on the stack by itself. A long thin string would buckle (bend sideways) under its own weight. So it is held in tension, and the tension is calculated from the effective axial force, the same quantity that decides the stability of a drill string (true and effective axial force). The effective weight of one metre of riser in the sea is the weight of its structure in water, $w_s$ , plus the difference between the weight of the mud inside and the weight of the sea water that the bore would displace: $g(\rho_m - \rho_{sw})A_{\text{bore}}$ . We add this up along the length and add the mud above the water. This gives the tension at which the effective force at the bottom of the riser is zero.

Least tension at the top of the riser

T_{\min} = w_s\,h_w + A_{\text{bore}}\,(p_m - p_{sw}), \qquad p_m = \rho_m\,g\,(h_w + h_a), \quad p_{sw} = \rho_{sw}\,g\,h_w

where:

$T_{\min}$ tension at the top of the riser at which the effective axial force at its bottom is zero, N
$w_s$ weight of one metre of the riser structure in sea water: pipes, lines, flanges and buoyancy modules together, without the fluid in the bore, N/m
$h_w$ depth of the sea; the length of the riser is taken equal to it, m
$h_a$ height of the rotary table (and of the flowline) above sea level, m
$A_{\text{bore}}$ area of the inner bore of the riser, m²
$p_m,\ p_{sw}$ pressure of the column of mud inside and of the sea water outside, at the bottom of the riser, Pa
$\rho_m,\ \rho_{sw}$ density of the mud and of the sea water (1030 kg/m³), kg/m³

Units: SI; in the examples, kN, MPa and g/cm³ ( $p = 0.00981\,\rho\,h$ MPa with $\rho$ in g/cm³)

Holds when

The riser is vertical and does not move. Current, waves and heave are not included. We neglect the height of the preventer stack above the seabed.
The mud stands as a column from the flowline at the height of the rotary table. While mud circulates, friction losses add to the pressure inside.
This is a lower limit. The tensioners are set higher, with a margin for the inaccuracy of the weight and of the buoyancy, for the friction and the tilt of the wire ropes, and for the sudden failure of a tensioner.

The first term is the weight of the structure itself, and the buoyancy modules take off almost all of it. The second term is the “extra” weight of the mud: a column of mud in the bore is heavier than a column of water of the same volume. The modules do not reduce it. So as the mud gets heavier and the sea gets deeper, the tension grows in proportion to the area of the bore.

Tensioner setting with a margin for a failure

T_{\text{set}} = \frac{N}{(N - n)\,\eta}\;T_{\min}

where:

$T_{\text{set}}$ total tension to which the tensioners are set, N
$N,\ n$ number of tensioners and the number of those that may fail at the same time, —
$\eta$ share of the force of the tensioners that reaches the riser along the vertical (friction, tilt of the wire ropes), —

Units: any one unit of force

Holds when

The load is shared equally between the tensioners. A failed tensioner stops pulling at once.
$\eta$ and the allowed number of failures are taken from the technical data of the rig and from the work plan. The values in the example are assumed.

The remaining $N - n$ tensioners must still give the riser at least $T_{\min}$ after a failure. While all of them work, the tension is larger than the least one, and the effective force at the bottom of the riser is positive. This is the margin that keeps the riser straight (see the advanced section).

Worked exampleRiser tension under 1200 m of water

Given (assumed data)

Sea depth $h_w$ ; rotary table above the sea $h_a$: 1200 m; 25 m
Riser: 533.4 × 488.9 mm (21″, wall 22.2 mm)
Weight of the structure in water $w_s$: with buoyancy modules 0.40 kN/m, without modules 3.60 kN/m (assumed)
Mud; sea water: 1.30 g/cm³; 1.03 g/cm³
Tensioners: 6, designed for the failure of one; $\eta = 0.95$ (assumed)

Solution

Area of the bore: $A_{\text{bore}} = \pi\cdot 0.4889^2/4 = 0.18773$ m².
Pressures at the bottom of the riser: mud $p_m = 0.00981\cdot 1.30\cdot(1200 + 25) = 15.622$ MPa, sea water $p_{sw} = 0.00981\cdot 1.03\cdot 1200 = 12.125$ MPa. The difference is 3.497 MPa.
Extra weight of the mud: $A_{\text{bore}}\,(p_m - p_{sw}) = 0.18773\cdot 3.497\cdot 1000 = 656.5$ kN (m² · MPa = MN).
Weight of the structure: with modules $0.40\cdot 1200 = 480$ kN, without modules $3.60\cdot 1200 = 4320$ kN.
Least tension with modules: $480 + 656.5 = 1136.5$ kN, about 116 tf (tonne-force; 1 tf = 9.807 kN). Without modules it is 4976.5 kN, about 507 tf.
Tensioner setting: $1136.5\cdot 6/(5\cdot 0.95) = 1435.6$ kN.
Each +0.10 g/cm³ of mud adds $0.00981\cdot 0.10\cdot 1225\cdot 0.18773\cdot 1000 = 225.6$ kN.

Answer: A riser with buoyancy modules needs at least 1136.5 kN (about 116 tf), and the tensioners are set to about 1435.6 kN. Without modules 4976.5 kN would be needed.

What it means. The modules took off almost 90% of the weight of the structure, and now 58% of the tension comes from the mud, which the modules do not offset. So every time the mud is made heavier, we must check the tension. A large riser margin (next section) is also paid for by an extra load on the tensioners. When sea water replaces the mud in the riser, for example before a planned disconnect, the tension falls almost to the weight of the structure, and we reset the tensioners. The data in this example are assumed for illustration.

CalculatedThe least tension of the riser with buoyancy modules from the example, against the sea depth, for sea water in the bore and for muds of 1.30 and 1.60 g/cm³. The calculation uses the formula above. The gap between the lines is the extra weight of the mud. The dot is the example of the lesson (1200 m, 1.14 MN).

Wind, waves and current push the rig off its position, and the riser tilts. The tilt at the lower joint is limited. At a large angle the drill pipe rubs on the joint and on the bottom of the riser, and the stack and the housing bend. So for every well we set the allowed offsets from the point above the wellhead. There is an inner circle, beyond which the crew starts to prepare for a disconnect, and an outer circle, beyond which the rig disconnects. The emergency disconnect sequence works automatically: the shear rams cut the pipe in the stack and close the well, and the lower marine riser package disconnects. The calculation in the advanced section shows how much more the bottom of the riser tilts than the top.

Pressures in deep water: riser margin and the choke line

In a well with a subsea wellhead the mud stands as a column from the flowline on the rig down to the bottom of the hole. So, as on land, we compare its density with the pore pressure and the fracture pressure. We write all three as equivalent mud weights: the density of a mud column that would give the same pressure, with depths measured from the rotary table. Deep water has two special features. The first is that the window is narrow. At the same depth from the rotary table the overburden pressure (the pressure from the weight of everything above) is lower than on land, because the upper hundreds or thousands of metres of the column are sea water, not rock (overburden pressure offshore). The second is that the column of mud above the seabed exists only while the riser is connected to the well.

If the riser is disconnected, as planned before a storm or in an emergency when the rig drifts, sea water takes the place of the mud above the wellhead, and the pressure at the bottom of the hole falls. The riser margin is how much the mud density must exceed the pore pressure (written as a density) for the well to stay under control after a disconnect. After the disconnect, a column of sea water from sea level presses on the wellhead. This is exactly the hydrostatic pressure of the sea (the pressure of a still column of water). So the mud below the seabed has to hold back only the excess of the pore pressure over the hydrostatic pressure of sea water.

Mud density with a riser margin

\rho_{\text{rm}} = \frac{\rho_{\text{p}}\,H - \rho_{sw}\,h_w}{H - h_a - h_w}, \qquad \Delta\rho_{\text{rm}} = \rho_{\text{rm}} - \rho_{\text{p}} = \frac{\rho_{\text{p}}\,(h_a + h_w) - \rho_{sw}\,h_w}{H - h_a - h_w}

where:

$\rho_{\text{rm}}$ mud density that holds the formation even after the riser is disconnected, g/cm³
$\rho_{\text{p}}$ pore pressure of the formation as an equivalent mud weight, measured from the rotary table, g/cm³
$\Delta\rho_{\text{rm}}$ riser margin, g/cm³
$\rho_{sw}$ density of sea water, about 1.03, g/cm³
$H$ true vertical depth of the formation from the rotary table, m
$h_a,\ h_w$ height of the rotary table above sea level and depth of the sea, m

Units: densities in the same unit (g/cm³), depths vertical, in metres

Holds when

After the disconnect there is sea water from sea level down to the wellhead, and the same mud stays below the seabed. The height of the stack above the seabed is not included.
The pressures are hydrostatic: there is no circulation, and there is no gas in the mud.
We calculate for the formation with the highest pressure in the open hole. If $\rho_{\text{rm}}$ is larger than the equivalent mud weight of the fracture pressure under the shoe, the margin cannot be reached.

The numerator is the shortage of pressure. A column of height $h_a + h_w$ that was “worth” $\rho_{\text{p}}$ at balance is, after the disconnect, worth $\rho_{sw}$ over the height $h_w$ and nothing above the water. Only the mud below the seabed can make up the shortage, so the denominator is the length of the hole below the seabed. The deeper the sea and the closer the formation is to the seabed, the larger the margin.

Worked exampleRiser margin for a formation 1500 m below the seabed

Given (assumed data)

Well: the teaching well: rotary table 25 m above the sea, sea depth 1200 m, surface casing at 700 m below the seabed
Formation: 1500 m below the seabed; its pressure is 4.0 MPa above the hydrostatic pressure of sea water from sea level (assumed)
Window model under the shoe: sediment density 2.0 g/cm³, fracture pressure $p_f = p_p + 0.6\,(\sigma_v - p_p)$ (an estimate from the effective stress); at the shoe the pore pressure is hydrostatic
Mud while drilling: 1.19 g/cm³

Solution

Depth of the formation from the rotary table: $H = 25 + 1200 + 1500 = 2725$ m. Pore pressure: $p_p = 0.00981\cdot 1.03\cdot 2700 + 4.0 = 31.282$ MPa. The equivalent mud weight from the rotary table is $\rho_{\text{p}} = 31.282/(0.00981\cdot 2725) = 1.170$ g/cm³.
After the disconnect there is sea water above the wellhead, with a pressure at the seabed of $0.00981\cdot 1.03\cdot 1200 = 12.125$ MPa. The rest must come from the mud over 1500 m below the seabed: $\rho_{\text{rm}} = (31.282 - 12.125)/14.715 = 1.302$ g/cm³, where $14.715 = 0.00981\cdot 1500$ . The riser margin is $1.302 - 1.170 = 0.132$ g/cm³. The formula above gives the same.
Fracture pressure under the shoe of the surface casing: the overburden pressure is $0.00981\cdot(1.03\cdot 1200 + 2.0\cdot 700) = 25.859$ MPa, the pore pressure is $0.00981\cdot 1.03\cdot 1900 = 19.198$ MPa, and the fracture pressure is $19.198 + 0.6\cdot(25.859 - 19.198) = 23.195$ MPa. From the rotary table this is $23.195/18.884 = 1.228$ g/cm³ ( $18.884 = 0.00981\cdot 1925$ ).
For the riser margin we need mud of 1.302 g/cm³, but the rock under the shoe will withstand no more than 1.228. Such a mud would fracture it. We drill with mud of 1.19 g/cm³, between 1.170 and 1.228.
If we disconnect with this mud, the pressure at the formation becomes $0.00981\cdot(1.03\cdot 1200 + 1.19\cdot 1500) = 29.636$ MPa, which is 1.65 MPa below the pore pressure.

Answer: The riser margin is 0.132 g/cm³ (mud of 1.302 g/cm³), but it cannot be reached: under the shoe no more than 1.228 g/cm³ is allowed. For the same section it could be reached in water shallower than 679 m.

What it means. In deep water this is the usual case. Then we drill the interval without the full margin, and the preventers hold the well during a disconnect. Before a planned disconnect we close the well with rams, and an emergency disconnect starts with the automatic closing of the shear rams. The price is that until the rig returns, the well has only one barrier (one thing that keeps it closed), the closed stack. The other ways out are to set the surface casing deeper or to add a string, or to drill with managed pressure (holding the pressure in the hole inside tight limits) or with two gradients (see the advanced section). The data in this example are assumed for illustration.

CalculatedThe same section under different sea depths (the model of the example): the pore pressure of the formation 1500 m below the seabed and the fracture pressure under the shoe 700 m below the seabed, both as equivalent mud weights from the rotary table, and the density needed for the riser margin. To the right of the crossing point the riser margin cannot be reached.

The second difference of a subsea wellhead is killing the well through a long line. When a kick happens (formation fluid flows into the well), the well is closed with the preventers on the seabed, and the flow goes to the choke of the rig along the choke line that runs along the riser (Well kill methods). On land this line is tens of metres long, and the friction in it is negligible. Under 1200 m of water it is longer than a kilometre and narrow. So its friction adds to the pressure at the choke and presses on the whole well below the stack, including the weak rock under the shoe.

Worked exampleFriction losses in the choke line

Given (assumed data)

Choke line: inner diameter 76.2 mm (3″), length from the stack to the choke 1225 m
Pump rate while killing: 6 L/s (0.36 m³/min)
Mud: 1.19 g/cm³; rheology as in the examples of the lesson on pressure losses: in pipes $n = 0.670$ , $K = 0.345$ Pa·sⁿ
Under the shoe of the surface casing: fracture 1.228 g/cm³ (the example above), 1925 m from the rotary table

Solution

Area of the bore $\pi\cdot 0.0762^2/4 = 0.004560$ m², velocity $v = 0.006/0.004560 = 1.316$ m/s.
The generalised Reynolds number (formula), which tells whether the flow is smooth or turbulent, is about 1628. It is below the limit $3470 - 1370\cdot 0.670 = 2552$ , so the flow is laminar (smooth).
The laminar loss of a power-law fluid (a fluid whose viscosity changes with the rate of flow) in a pipe (formula) is 531.2 Pa/m. For the whole line this is $531.2\cdot 1225 = 650.7$ kPa, that is 0.651 MPa.
The allowed annulus pressure at the surface with this mud (MAASP): $(1.228 - 1.19)\cdot 0.00981\cdot 1925 = 0.72$ MPa.
The losses in the line are 90% of this allowance.

Answer: At a pump rate of 6 L/s the choke line “eats” 0.651 MPa, about 90% of the allowed annulus pressure at the surface (MAASP).

What it means. If we kept the pressure at the choke the same when the pump starts, as on land, the pressure in the whole well below the stack would rise by 0.651 MPa, and the rock under the shoe would be at the edge of fracturing. So we measure the losses in the line in advance, from the difference in the standpipe pressure when mud circulates at a reduced rate through the choke line and through the riser. When the pump starts, we lower the pressure at the choke by this amount. The crew watches the pressure in the kill line, in which nothing flows. It shows the pressure at the stack. If the losses are larger than the pressure of the closed well, even a fully open choke cannot remove them. Then we kill the well at a lower rate, or send the flow through both lines at once. The data in this example are assumed for illustration.

Gas under the closed stack. After killing, gas may stay under a closed preventer. If the stack is opened, the gas goes up into the riser. We carefully circulate it out through the choke line before we open the preventers.
Gas in the riser. Gas that has slipped above the stack before it closed rises up the riser and expands fast near the surface (how gas behaves in the well). The diverter sends it away.
Cold at the seabed. In deep water the temperature at the seabed is a few degrees above zero. When circulation stops, gas hydrates (ice-like solids made of gas and water) can form in the stack and in the lines. We prevent them by pumping inhibitors (chemicals that stop hydrates from forming) and by the choice of the mud.

The shallow section: gas and sands under pressure

The first hundreds of metres below the seabed are drilled when the well has neither a riser nor preventers yet, and the rock at the conductor shoe is weaker than anywhere below. The well cannot be closed here. So we do not try to meet the hazards of this interval; we try to avoid them.

Shallow gas is gas in sands under thin clay seals (clay layers that hold the gas back) at a depth of tens or hundreds of metres. On a rig that rests on the seabed, the diverter sends the flow away. A floating rig drills this interval without a riser. The gas comes out at the seabed and rises to the surface. The bubbles lower the density of the water over the wellhead, and they can reduce the buoyancy and the stability of the rig. So the crew is ready to move the rig away from the place where the gas comes out.
Sands with water under pressure (shallow water flow). In deep-water sediments that built up quickly, a sand under poorly compacted clay can have a pressure above the hydrostatic pressure. Water with sand comes out through the annulus onto the seabed and washes out the soil around the conductor. The conductor can then sink or tilt, and the base of the wellhead can no longer be repaired.
Gas hydrates in the sediments. In deep water it is cold and the pressure is high, and hydrate can occur in the pores near the seabed. When the heat of circulation breaks it down, it releases gas and weakens the soil.
An uneven and unstable seabed. Boulders, buried channels, steep slopes and landslides are dangerous both for the conductor and for the legs of a jack-up.
Ice. In freezing shallow water, drifting ice presses on structures, and ice ridges (piles of broken ice) gouge the seabed. A subsea wellhead in shallow water would be under threat. In the northern Caspian the operator names ice movements and furrows in the seabed among the main limits for construction and work.

The main protection is a forecast: site surveys and a high-resolution seismic survey of the site (gas-bearing sands show up as amplitude anomalies, see direct hydrocarbon indicators), choosing a point away from anomalies, and data from neighbouring wells. After that comes the way we drill: a pilot hole of small diameter (the flow from a narrow hole is smaller and easier to kill), a weighted mud kept ready, frequent surveys, and watching the wellhead with the camera of the underwater vehicle.

Worked exampleWhich mud will hold a sand when the returns go to the seabed

Given (assumed data)

Well: the teaching well: sea depth 1200 m; the 660.4 mm (26″) hole for the surface casing is drilled without a riser
Sand: 350 m below the seabed; its pressure is 0.50 MPa above the hydrostatic pressure of sea water from sea level (assumed)
Weighted mud kept ready: 1.25 g/cm³ (assumed)

Solution

While we circulate sea water in the hole, the pressure in it at the sand is the hydrostatic pressure of the sea: $0.00981\cdot 1.03\cdot(1200 + 350) = 15.662$ MPa. In the sand it is $15.662 + 0.50 = 16.162$ MPa. Water with sand will flow into the well.
Sea water still stands above the wellhead. So the fluid below the seabed must be no lighter than $1.03 + 0.50/(0.00981\cdot 350) = 1.176$ g/cm³.
With a mud of 1.25 g/cm³ the pressure at the sand is $0.00981\cdot(1.03\cdot 1200 + 1.25\cdot 350) = 16.417$ MPa, which is 0.255 MPa above the pressure in the sand.
The volume of the 660.4 mm hole is $\pi\cdot 0.6604^2/4 = 0.3425$ m³ per metre. From the conductor shoe (75 m) to the surface casing shoe (700 m) it is $0.3425\cdot 625 = 214$ m³, without washouts (enlarged parts of the hole).

Answer: Sea water will not hold the sand. We need a mud no lighter than 1.176 g/cm³. A mud of 1.25 g/cm³ gives 0.255 MPa of margin. But each filling of the open hole means about 214 m³ of mud left on the seabed.

What it means. So we drill the top interval with sea water and viscous sweeps. We prepare the weighted mud in advance, in large volumes, and pump it when signs of an influx appear and before we run the surface casing. In Kazakhstan, in offshore exploration and production of hydrocarbons, it is forbidden to discharge waste into the sea or to bury it on the seabed (Subsoil Code, Article 159). For the nature reserve zone of the northern Caspian, the Environmental Code names cuttings and muds directly as drilling waste. They may be pumped into the subsoil only after the neutralisation that the project provides for. Waste that is not reused and not pumped down is neutralised and stored at a landfill outside the zone (Article 274, paragraphs 7 and 9). In the shallow northern Caspian, releasing mud onto the seabed is not even needed: wells there are drilled from islands and barges with the wellhead above the water, and the mud returns to the surface. The data in this example are assumed for illustration.

Completion, suspension and abandonment of a subsea well

A subsea well that has been drilled is either completed at once (equipped for production), or suspended so that we can return to it later, with the same or another rig. In both cases the rule is the same: before the preventers are taken off, there must be at least two independent, tested barriers between the formation and the sea (primary and secondary control). The two barriers can be, for example, a packer (a seal that closes the space between the tubing and the casing) with tubing (the pipe through which the well produces) and a plug, and a pressure-tested casing string with its hanger and seal.

Two types of subsea tree

: Where the tubing hanger is
Vertical: in the wellhead housing, under the tree
Horizontal: in the body of the tree itself

: Order of work
Vertical: the tubing is run through the preventers, plugs are set, the preventers are removed and the tree is installed
Horizontal: the tree is installed on the housing, the preventers on top of it, and the tubing is run through them into the tree

: Main valves
Vertical: in the vertical bore above the hanger
Horizontal: on the side outlet; the vertical bore is closed with plugs

: Workover (repair of a producing well) that pulls the tubing
Vertical: the tree must be taken off
Horizontal: the tubing is pulled without taking the tree off

	Vertical	Horizontal
Where the tubing hanger is	in the wellhead housing, under the tree	in the body of the tree itself
Order of work	the tubing is run through the preventers, plugs are set, the preventers are removed and the tree is installed	the tree is installed on the housing, the preventers on top of it, and the tubing is run through them into the tree
Main valves	in the vertical bore above the hanger	on the side outlet; the vertical bore is closed with plugs
Workover (repair of a producing well) that pulls the tubing	the tree must be taken off	the tubing is pulled without taking the tree off

The choice depends on how often workovers that pull the tubing are expected, on the size of the tubing string, and on which rig will do the work.

With a vertical tree, completion goes like this. The tubing string with a packer, a subsurface safety valve (a valve deep in the tubing that shuts the well in an emergency) and its control line (Completion string equipment) is run through the riser and the preventers on a running string, and the hanger is landed in the housing. The crew pressure-tests the string, the packer, the seals of the hanger and the working of the safety valve, and sets plugs in the tubing. Only with these barriers in place is the preventer stack taken off. The tree is run on a special riser with its own small preventer stack and a control panel, latched on the housing and tested. Then the crew perforates the casing (makes holes in it opposite the formation), makes the well flow and cleans it up, closes it with the valves and installs the tree cap. The well is connected to the pipeline and to the control cable later, from a special vessel.

In suspension (the official word in Kazakhstan is “conservation”), cement plugs or mechanical plugs are set in the well, so that two barriers separate the formation. We close the housing with a protective cap against corrosion and silt. We mark the well on charts and monitor it. Later the crew returns to it, removes the cap, installs the preventers and the riser and goes on with the work.

Abandonment of a subsea well (the official word is “liquidation”) starts as on land: cement plugs opposite the formations, at the shoes and near the surface (abandonment and suspension of wells). Then we cut all the strings below the seabed, from the inside, with a mechanical or an abrasive water-jet cutter. We lift the housing with the cut pieces of the strings and the guide base, and we survey and clean the seabed. National rules set the depths at which to cut. Abandonment needs a rig or a special vessel and is expensive, so it is planned and funded already when the field is developed.

Kazakhstan: a project for an offshore well: offshore wells, like complex ones, are suspended and abandoned under a project of a licensed design organisation that has passed the expert reviews (the Rules for conservation and liquidation in the exploration and production of hydrocarbons, Order of the Minister of Energy No. 200 of 22 May 2018, annex 8, paragraphs 5 and 8–9).
Suspension of an offshore well (paragraphs 17, 20): the hole is filled with drilling mud treated with surfactants (surface-active chemicals) and neutralisers, with a hydrostatic pressure 15% above the formation pressure. A cement plug is set at the perforation interval. Paragraph 17, which applies to complex and offshore wells, requires at least 100 m above the perforations. Paragraph 20 names for an offshore well a plug “50 metres high, 20 metres below the perforation interval and 50 metres above it”. A cement plug at least 50 m thick is set at the wellhead. The blowout preventer equipment is not removed for the time of suspension. An acoustic sensor for the suspended well is installed at the wellhead. Divers inspect the wellhead and the seabed around it for navigation hazards and draw up an act, a signed official report (paragraph 20).
Abandonment of an offshore well (paragraphs 36–38): all casing strings are cut below the seabed, and the wellhead is filled with cement slurry up to the level of the seabed. After it hardens, the wellhead and the seabed next to it are covered with large concrete slabs or blocks. Divers survey the seabed, and the act of the survey, with coordinates, is passed to the service responsible for the safety of navigation.
Environmental Code, Article 279: when a well is suspended after testing, the drilling base is kept and the well is reliably sealed until work is resumed (paragraph 2). Wells drilled from a fill base (an underwater berm, which is a raised bank of fill, or an island) are sealed when they are abandoned, and the artificial base is monitored after it has been cleaned of contamination. If an island is washed away, it is marked by a pole or a buoy until the final levelling, and the coordinates are passed on for sea charts (paragraph 3). When wells drilled from platforms are abandoned, the platforms are removed completely, and the wellheads are cut off at the level of the seabed (paragraph 4).

This summary follows the texts as of October 2026. Paragraphs 17 and 20 set the plug above the perforations in different ways: the first says at least 100 m, the second says “50 metres high” and reaching 20 m and 50 m beyond the interval. In the Kazakh text of paragraph 20 the two sides are swapped: 20 m above and 50 m below the interval. The general requirements for plugs when complex and offshore wells are abandoned (paragraph 31 of the same annex) are covered in the lesson on remedial cementing. A particular well is suspended and abandoned under its own project, which has passed the expert reviews.

The northern Caspian: shallow water, ice and the nature reserve zone

The first large offshore project of Kazakhstan is the development of the Kashagan field in the shallow northern Caspian. Its reservoir lies about 80 km from Atyrau under 3–4 m of water, and it is deeper than 4 km, about 4200 m below the seabed. The pressure in it is high, and the oil and gas contain a lot of hydrogen sulfide (a poisonous gas) and carbon dioxide. Because of the inflow of fresh water from the Volga, the shallow water and the cold winters, this part of the sea is covered with ice for about five months a year. The operator names the movements of the ice and the furrows that the ice leaves in the seabed among the main limits for construction, production and supply (the operator's data as of October 2026).

Neither a floating rig nor a subsea wellhead suits the place. A floating rig would not have enough depth, and a wellhead on the seabed a few metres below the surface would be swept away by the ice. The first exploration well, Kashagan East-1, was started in August 1999 from the drilling barge Sunkar, which had been converted for the Caspian. The discovery was announced in the summer of 2000. For the development, artificial islands were built. Today the offshore complex is five islands. Island D is the centre of production, primary separation and gas reinjection. Island A and the islands EPC-2, EPC-3 and EPC-4 are islands for drilling and production. Drilling on island D started in July 2006 with two drilling rigs. Oil and gas go to the shore through field pipelines, to the Bolashak plant (offshore development).

On an island the rig stands almost as on land: the wellhead and the preventers are above the surface, with an ordinary wellhead stack. We drill several inclined wells from one island to different parts of the accumulation (the body of oil and gas in the rock; see Directional wells: applications and profile). What is special about offshore work is the supply and the seasons. The main supply base, Bautino, is in the ice-free Tupkaragan Bay, about 280 km south-west of the field in a straight line. In winter the sea at the field is under ice, and part of the work in the nature reserve zone is limited by season (see below).

Work at sea is regulated by the chapter of the Subsoil Code on the exploration and production of hydrocarbons at sea, and by the chapter of the Environmental Code on the state nature reserve zone in the northern part of the Caspian Sea. As early as 1993 the North Caspian project was allowed to work on condition that it kept the special environmental requirements for activity in this zone (according to the operator). For building wells the main points, from the texts of the codes as of October 2026, are these:

Subsoil Code, Article 154: artificial islands, dams, structures, installations, pipelines and other objects of exploration and production at sea are offshore objects (paragraph 4). In exploration at sea, wells may be drilled only after all the necessary geophysical and seismic studies, and when the oil spill preparedness requirements are met (paragraph 10). It is forbidden to drill a well that is not provided for by an approved drilling project that has passed the expert reviews. The exception is a relief well (a well drilled to kill a blowout) for an open blowout that cannot be brought under control otherwise, with notice to the competent authority (paragraph 11).
Subsoil Code, Articles 155–159: oil spills are divided into three levels: up to 10 t, from 10 to 250 t, and from 250 t (Article 155). It is allowed to work at an object with a spill risk only with a risk assessment, an approved plan and resources for clean-up. The resources for a first-level spill must be on the offshore object or within 30 minutes' reach (Article 156). Offshore objects are created and placed by permit, with safety zones of 500 m around them, and after the work ends they are dismantled if they cannot be used further (Article 157). Oil may not be stored at sea, except for temporary storage of up to 20 calendar days when it is taken away by tankers directly from the offshore objects (Article 158). It is forbidden to discharge waste into the sea and to bury it on the seabed. Waste water may be discharged only by permit, after treatment to the standards (Article 159).
Environmental Code, Article 269: from 1 April to 15 July, in the areas near the mouths of the Ural and the Volga (within 50 km of the points of their deltas that extend furthest into the sea) and in the 15-kilometre coastal strip between them and further east to the Emba river, construction and geophysical work, well testing and shipping are forbidden (except fishing vessels, navigation-support vessels and scientific work). Production at this time switches to autonomous supply, and waste is stored until the ban ends. From October to May, operations are held no closer than 1852 m (one nautical mile) to the places where Caspian seals gather. The building of drilling bases, well testing and shipping are limited already at the design stage. Inside the zone there are protected areas where any activity is forbidden.
Environmental Code, Articles 273–274: blasting in the water column and on the seabed is forbidden, and under the seabed it is allowed only by permit. It is not allowed to discharge waste into the sea, and waste water either, except a limited list of treated waters by permit. Burning fluids at a flare during the operation of wells is forbidden, except when there is a threat of an accident. During tests it is kept to a minimum, with the best available technique and only in weather that disperses the smoke. Drilling waste is pumped into the subsoil only after the neutralisation that the project provides for. Waste that is not pumped down and not reused is neutralised and stored at a landfill outside the nature reserve zone, which is put in place before drilling begins. Drilling and cementing fluids may contain only substances agreed in the approved project. In the water protection zone and on shallow coastal areas down to 10 m deep, wells are drilled with rigs that have an electric drive powered from external grids. When the drive is diesel, the release of untreated exhaust gases is kept to a minimum.
Environmental Code, Article 280: the subsoil user carries out annual production monitoring (its own monitoring of the environment) by seasons on the whole contract territory, except winter monitoring on the ice-covered water area.

This summary is short and does not replace the texts of the codes. The requirements for a particular well are set by its project, which has passed the expert reviews, by the environmental permits and by the industrial safety rules (State regulation of field development).

Terms and symbols

Marine drilling riser: A string of pipe between the subsea preventer stack and the floating rig. It is a channel for mud and tools, and it carries the choke and kill lines.
Lower marine riser package (LMRP): The detachable upper part of the subsea stack, with the annular preventers and the controls.
Low-pressure wellhead housing: The support housing on the conductor. The high-pressure housing sits in it.
High-pressure wellhead housing: The housing on the surface casing, with a bore of 476 mm (18¾″). All the next strings are hung and sealed in it, and the preventers and the tree are set on it.
Jetting a conductor: Sinking the conductor into soft soil under its own weight while a jet of water washes away the soil at the shoe.
Mudline suspension system: Hangers of the casing strings at the level of the seabed in wells of jack-up rigs.
Riser margin: The excess of mud density that keeps the well under control even after the riser is disconnected.
Dynamic positioning: Holding a floating rig over a point with thrusters, using signals from navigation systems (DP).
Choke line friction: Friction in the long line from the subsea stack to the choke. While we kill the well, it adds to the pressure in the well.
Vertical and horizontal tree: A subsea tree with the tubing hanger in the housing under the tree (vertical), or in the tree itself (horizontal).

Common mistakes and misconceptions

Wrong

“Deep water just means a longer string; the casing programme is the same as on land.”

In fact

Water is lighter than rock, so the overburden pressure and the fracture pressure in the upper intervals are lower, and the window is narrower. More strings are needed. The upper intervals are drilled without a riser and preventers, and the well is killed through a long line with large friction.

Wrong

“Buoyancy modules take off the load of the mud as well.”

In fact

The modules reduce the weight of the structure. The extra weight of the mud, $A_{\text{bore}}(p_m - p_{sw})$ , stays on the tensioners and grows with its density.

Wrong

“The mud holds the formation with a margin, so disconnecting the riser is no danger.”

In fact

After the disconnect, sea water replaces the column of mud above the seabed. Without a riser margin the formation is no longer under control, and only the closed rams hold the well.

Wrong

“A floating rig finds it easier to work in shallow water than in deep water.”

In fact

The tilt of the riser depends on the ratio of the offset to the depth. At a small depth the same drift gives an angle that is several times larger. And at a depth of a few metres a floating rig cannot be placed at all. There wells are drilled from barges and islands, and at depths of tens of metres from jack-ups.

Wrong

“To abandon a subsea well is just to set plugs.”

In fact

We must also cut the strings below the seabed, lift the wellhead equipment, and survey and clean the seabed. In Kazakhstan the wellhead of an offshore well is filled with cement up to the level of the seabed and covered with concrete slabs, and the act with the coordinates is passed to the service for the safety of navigation.

In depth: advanced detail

Why the bottom of the riser tilts more than the top

If current and waves do not act on the riser, the horizontal component of the force in it is the same along its whole length. It is passed from the rig to the wellhead. This component equals the tension multiplied by the slope, $T\,\dd y/\dd z$ . The effective tension grows from the bottom up by the weight of each metre. So where the tension is smaller, at the bottom, the riser is tilted more. If we integrate the slope along the length (add it up over the whole length), with a tension that grows steadily with height, we get the angles at the ends.

Angles at the bottom and at the top of a tensioned riser

\tan\theta_{\text{bot}} = \frac{T_{\text{top}} - T_{\text{bot}}}{T_{\text{bot}}\,\ln(T_{\text{top}}/T_{\text{bot}})}\cdot\frac{x}{L}, \qquad \tan\theta_{\text{top}} = \frac{T_{\text{bot}}}{T_{\text{top}}}\,\tan\theta_{\text{bot}}

where:

$\theta_{\text{bot}},\ \theta_{\text{top}}$ angles of the riser with the vertical at the lower and at the upper joint, °
$T_{\text{top}},\ T_{\text{bot}}$ effective tension at the top (at the water surface) and at the bottom of the riser, kN
$x$ offset of the rig from the point above the wellhead, m
$L$ length of the riser (here, the sea depth), m

Units: any consistent units: the tensions in one unit, $x$ and $L$ in one unit

Holds when

The riser is a taut string: its bending stiffness matters only at the ends. There is no current and no waves, and the offset is static.
The effective weight of one metre is the same along the length, and the tension grows linearly from the bottom up: $T_{\text{top}} - T_{\text{bot}} = w\,L$ .
The top of the riser is taken at the water surface. The part above the water up to the upper joint is not included. With it, the angles are a little smaller for the same offset, so the calculation is on the safe side.
The angles are small: the tangent is close to the angle in radians.

The first factor shows how many times the angle at the bottom is larger than the mean slope $x/L$ . It is larger the smaller the tension at the bottom is. As $T_{\text{bot}} \to 0$ the angle at the bottom grows without limit. That is why we set the tension with a margin above the least tension. The allowed offset is proportional to the sea depth, and it is given as a percentage of the depth.

Worked exampleRiser angles at an offset of 1% of the sea depth

Given (assumed data)

Riser: from the example on tension: $T_{\min} = 1136.5$ kN, the tensioners are set to 1435.6 kN, $\eta = 0.95$ , all of them work
Sea depth and offset of the rig: 1200 m; 12 m
Allowed angle of the lower joint: 2° (assumed)

Solution

Tension at the top, at the water surface: the force of the tensioners, less the column of mud above the sea, which they also carry, is $1435.6\cdot 0.95 - 59.85 = 1304.0$ kN, where $59.85 = 0.18773\cdot 0.00981\cdot 1.30\cdot 25\cdot 1000$ . At the bottom it is $1435.6\cdot 0.95 - 1136.5 = 227.3$ kN. The ratio is 5.74.
The factor: $(1304.0 - 227.3)/(227.3\cdot\ln 5.74) = 2.71$ .
Mean slope $\arctan(12/1200) = 0.573$ °. The angle at the bottom is $\arctan(2.71\cdot 0.01) = 1.55$ °, and at the top it is 0.27°.
Allowed offset at 2° at the bottom: $1200\cdot\tan 2°/2.71 = 15.5$ m, which is 1.29% of the sea depth. Under 100 m of water, with the same ratio of tensions, it is only 1.29 m.

Answer: At an offset of 1% of the sea depth the lower joint tilts by 1.55°, almost three times the mean slope, and the upper joint by 0.27°. The allowed offset is about 15.5 m.

What it means. The most vulnerable part of the riser is the bottom: it has both the largest angle and the least tension. If a tensioner fails, the tension at the bottom falls to zero (this is how the setting is calculated), and with the same drift the angle there grows sharply. So when a tensioner fails, the crew checks at once whether it is time to disconnect. The calculation also shows why a floating rig is cramped in shallow water: the allowed circle is proportional to the depth. Programs calculate the real angles with current, waves and bending stiffness (how much the riser resists bending). The data in this example are assumed for illustration.

How much load the soil holds for a conductor

A jetted conductor is held by the adhesion of the soil to its outer wall. We ignore the support under the open end of the pipe in soft clay. The adhesion is written as a fraction $\alpha$ of the undrained shear strength of the clay, $s_u$ (the strength of the clay when the water cannot escape quickly from its pores), which grows with depth. Right after jetting, the soil at the wall is churned up and liquefied, and $\alpha$ is small. With time the extra pressure in the pores drains away, the clay regains its structure, and the adhesion grows several times. So after the installation we wait before we disconnect the running tool, and we wait still longer before we load the conductor.

Capacity of a conductor along its side surface

Q = \pi D\,\alpha\int_0^{L} s_u(z)\,\dd z = \pi D\,\alpha\left(s_{u0}\,L + \frac{k\,L^2}{2}\right) \quad \text{for}\ s_u = s_{u0} + k\,z

where:

$Q$ force that the soil holds by friction and adhesion along the wall, kN
$D$ outer diameter of the conductor, m
$\alpha$ the fraction of the clay strength that is used at the wall: small right after jetting, growing with time, —
$s_u,\ s_{u0}$ undrained shear strength of the clay at depth $z$ and at the seabed, kPa
$k$ increase of strength with depth, kPa/m
$L,\ z$ length of the conductor in the soil and the depth below the seabed, m

Units: kN, m, kPa

Holds when

Soft clay. We ignore the support under the end of the open pipe, which is on the safe side.
We take $s_u$ and $\alpha$ from site surveys and from the experience of installation on neighbouring wells. The values in the example are assumed.
Cyclic bending (bending that repeats again and again) from the riser and the stack weakens the soil at the top of the conductor with time. We take it into account separately.

The strength grows with depth, so the capacity grows faster than the length. If the strength at the seabed is small compared with its increase along the length, as in the example below, making the conductor one and a half times longer more than doubles the capacity (for $s_{u0} = 0$ , by a factor of 2.25).

Worked exampleLength of a jetted conductor

Given (assumed data)

Conductor: 914.4 mm (36″), wall 25.4 mm; weight in water 4.75 kN/m, and 90 kN for the low-pressure housing (assumed)
Soil: soft clay, $s_u = 2 + 1.5\,z$ kPa (assumed)
Factor $\alpha$: 0.25 right after jetting, 0.75 after waiting several days (assumed)
Load when the preventers are landed: 4000 kN including a design factor (assumed)

Solution

Capacity: $Q = \pi\cdot 0.9144\cdot\alpha\cdot(2L + 0.75L^2)$ kN.
After waiting ( $\alpha = 0.75$ ): $0.75L^2 + 2L = 4000/(\pi\cdot 0.9144\cdot 0.75) = 1856.6$ , so $L = 48.4$ m.
If the load had to be carried right after jetting ( $\alpha = 0.25$ ): $0.75L^2 + 2L = 5569.7$ , and $L = 84.9$ m.
Check right after the tool is disconnected, for a conductor 50 m long: the soil holds $\pi\cdot 0.9144\cdot 0.25\cdot(2\cdot 50 + 0.75\cdot 50^2) = 1418$ kN, and the conductor with its housing weighs $4.75\cdot 50 + 90 = 327.5$ kN in water.

Answer: With waiting, a conductor about 48.4 m long is enough, which we round to 50 m. Without waiting, 84.9 m would be needed. Right after installation, a 50 m conductor holds 1418 kN against its own weight of 327.5 kN, and it will not sink.

What it means. Time helps: a few days between installing the conductor and running the preventers cut the length needed almost by half. We choose the real length with a margin for the uncertainty of the clay strength, for the washing out of the soil near the seabed by the flow coming out, and for the bending from the riser. We refine the length and the waiting time from the experience of neighbouring wells. The data in this example are assumed for illustration.

When the window is too narrow: managed pressure and two gradients

The narrow window in deep water comes from the fact that above the seabed there is a column of mud, not of sea water. So engineers have developed methods of drilling that change this column. In managed pressure drilling (MPD), the annulus is closed under a rotating control device (a seal that lets the string rotate), and we regulate the pressure at the bottom of the hole with a choke at the surface. A lighter mud can be used, and back pressure can be added when the pump stops. In dual-gradient drilling (a gradient is how fast the pressure grows with depth, and here there are two, one for sea water and one for mud), a pump that stands on the seabed lifts the mud from the wellhead to the rig through a separate line. Above the seabed the riser holds a fluid with the density of sea water, or the level of mud in the riser is lowered with a pump. Then the pressure at the wellhead equals the hydrostatic pressure of the sea, as in a well without a riser.

Worked exampleThe window of the teaching well with two gradients

Given (assumed data)

Well and formation: from the example on the riser margin: the formation 1500 m below the seabed with a pore pressure of 31.282 MPa, and the fracture pressure under the shoe at 700 m below the seabed of 23.195 MPa
Above the seabed: a column with the density of sea water; the pressure at the seabed is 12.125 MPa

Solution

The lower limit of the mud density below the seabed is set by the pore pressure: $(31.282 - 12.125)/(0.00981\cdot 1500) = 1.302$ g/cm³.
The upper limit is the fracture pressure under the shoe: $(23.195 - 12.125)/(0.00981\cdot 700) = 1.612$ g/cm³.
With a mud of 1.35 g/cm³ the pressure at the formation is $12.125 + 0.00981\cdot 1.35\cdot 1500 = 31.990$ MPa, which is 0.71 MPa above the pore pressure. Under the shoe it is $12.125 + 0.00981\cdot 1.35\cdot 700 = 21.395$ MPa, which is 1.80 MPa below the fracture pressure.
With one gradient and a mud of 1.19 g/cm³, the same margins were 0.53 and 0.72 MPa.

Answer: With two gradients the mud density below the seabed can be chosen from 1.302 to 1.612 g/cm³, and no riser margin is needed: a disconnect does not change the pressure at the seabed.

What it means. We do not compare the window in densities directly with the earlier one, because the reference point has changed. We compare pressures. With a mud of 1.35 g/cm³ both the margin over the pore pressure and the margin to the fracture pressure under the shoe are larger than with one gradient. The reason is that above the seabed the pressure now grows with the gradient of sea water, and below the seabed with the gradient of the mud, which is close to the growth of pressures in the rock. The price is subsea pumps, a separate line and complex control. So such systems are used where an ordinary casing programme would need too many strings. The data in this example are assumed for illustration.

Connections to other topics

Blowout prevention equipment — preventers, the diverter and the subsea stack in outline.
Wellheads and running casing — casing heads, hangers and seals on land. A subsea wellhead works on the same principles.
Casing: purpose, types, properties and standards — the purpose of the strings, the conductor and the surface casing, and the combinations of strings and bits.
Pore pressure and overburden pressure — overburden pressure offshore, and equivalent mud weights measured from the rotary table.
Fracture gradient and leak-off testing — fracture pressure, the leak-off test and MAASP.
Well control: primary barrier and kick indicators — barriers, the signs of a kick and the behaviour of gas in the well.
Well kill methods — killing the well through the choke. At a subsea wellhead the losses in the choke line are added to it.
Drill string design — the effective axial force, the same as in the calculation of the riser tension.
Circulating pressure losses — friction pressure losses in pipes, here for the choke line.
Primary cementing — cementing the conductor and the surface casing through an inner string.
Remedial cementing, cement plugs and cement evaluation — cement plugs and the requirements of the rules of Kazakhstan for abandoning wells.
Completion string equipment — the packer, the safety valve and the tubing hanger of a subsea completion.
Field development concepts: surface facilities — platforms, subsea tie-backs and artificial islands as ways to develop a field.
Drilling time and cost — the time and the cost of a well. At sea there is an expensive rig, weather and ice.

Check yourself

1
An exploration well is drilled under 600 m of water. Where will the preventers stand after the surface casing is run?
1. A.On the seabed, on the subsea wellhead; a riser joins them to the rig
2. B.Nowhere: at this depth we drill to the bottom without a riser and preventers
3. C.On the seabed, and no riser is needed: the mud comes out onto the seabed
4. D.On the deck of the rig, as on land
Show the answer
Correct answer: A. On the seabed, on the subsea wellhead; a riser joins them to the rig
Only floating rigs, semi-submersibles and drillships, work under 600 m of water. Jack-ups are usually rated for depths up to 120 m, and some up to 150 m. A floating rig must be able to disconnect and move away. So the preventers stand on the housing at the seabed, and the mud returns through the riser. Only the top interval, down to the surface casing, is drilled without a riser.
2
The rotary table is 20 m above sea level, the sea is 800 m deep, and the formation with the highest pressure in the open hole is 2200 m below the seabed. Its pore pressure is equivalent to 1.20 g/cm³ from the rotary table. What mud is needed for the riser margin?
Show the answer
The depth of the formation from the rotary table is $H = 20 + 800 + 2200 = 3020$ m. $\rho_{\text{rm}} = (1.20\cdot 3020 - 1.03\cdot 800)/(3020 - 20 - 800) = (3624 - 824)/2200 \approx 1.273$ g/cm³. The riser margin is about 0.073 g/cm³. It still has to be compared with the fracture pressure under the shoe.
3
Under 1200 m of water the mud was made heavier, from 1.30 to 1.50 g/cm³. How will the least tension of the riser with buoyancy modules from the example of the lesson change?
1. A.It will not change: the buoyancy modules offset the mud too
2. B.It will grow by about 45 kN
3. C.It will grow by about 450 kN
4. D.It will fall: a heavy mud presses the riser against the stack
Show the answer
Correct answer: C. It will grow by about 450 kN
The extra weight of the mud, $A_{\text{bore}}(p_m - p_{sw})$ , grows. Each 0.10 g/cm³ on a column of 1225 m is $0.00981\cdot 0.10\cdot 1225\approx 1.20$ MPa, multiplied by the area of the bore of 0.188 m², which is about 226 kN. For 0.20 g/cm³ it is about 450 kN. The buoyancy modules carry only the structure.
4
Which of the following does the Environmental Code allow in the state nature reserve zone in the northern part of the Caspian Sea?
1. A.Burning gas at a flare during the ordinary operation of a well
2. B.Pumping drilling waste into the subsoil after the neutralisation that the project provides for
3. C.Testing a well on 1 May, 30 km from the point of the Ural delta that extends furthest into the sea
4. D.Storing drilling waste on the island until the work ends
Show the answer
Correct answer: B. Pumping drilling waste into the subsoil after the neutralisation that the project provides for
Burning fluids at a flare during the operation of wells is forbidden, except when there is a threat of an accident (Article 274, paragraph 3). Drilling waste that is not reused and not pumped into the subsoil is neutralised and stored only at a landfill outside the nature reserve zone (paragraph 9). Pumping drilling waste into the subsoil is allowed after the neutralisation determined by the approved project (paragraph 7). From 1 April to 15 July, well testing is forbidden within 50 km of the point of the Ural delta that extends furthest into the sea (Article 269).
5
Why is the top interval on a floating rig usually drilled without a riser, what is the price of this, and what does the law say about discharge onto the seabed for the Kazakhstan part of the Caspian?
Show the answer
Before the surface casing with the high-pressure housing is set, there is nothing to mount the preventers on, and the rock under the conductor is too weak to close the well. A riser without preventers would bring shallow gas straight to the rig in a blowout. So we drill the interval with sea water and let the mud come out onto the seabed, and we avoid the hazards by forecasting and by choosing the point. The price is the lack of control over an influx, and mud that goes to the seabed. In offshore exploration and production of hydrocarbons it is forbidden to discharge waste into the sea and to bury it on the seabed (Subsoil Code, Article 159), and the Environmental Code names cuttings and muds for the nature reserve zone directly as drilling waste (Article 274). Besides, in the shallow northern Caspian wells are drilled from islands and barges with the wellhead above the water, and the mud with the cuttings returns to the surface.
6
With which type of subsea tree can the tubing string be pulled for a workover without taking the tree off the wellhead?
1. A.With a horizontal one
2. B.With either
3. C.With neither
4. D.With a vertical one
Show the answer
Correct answer: A. With a horizontal one
In a horizontal tree the tubing hanger sits in the body of the tree, the valves are on the side outlet, and the vertical bore is closed with plugs. Preventers are installed on the tree, and the tubing is pulled through them. In a vertical tree the hanger is in the housing under the tree, so to pull the tubing the tree must be taken off.

Updated: 28 October 2026