Reservoir and seal

Quick refresher

Porosity decides how many hydrocarbons the rock can hold, and permeability decides whether we can produce them. Oil in a tight rock with no permeability is a discovery without production.
The quality of a clastic reservoir (a reservoir made of grains, such as sandstone) is set by the size and sorting of the grains (how alike they are in size). These in turn are set by the depositional environment. After burial, compaction (squeezing by the weight of the rocks above), cementation (new minerals gluing the grains together) and dissolution change the rock. In carbonates the main role is often played by secondary porosity, which means pores that formed after deposition.
Seals are clays, shales (argillites), salt, anhydrite and tight carbonates. They are not perfectly impermeable. Their tiny pores are filled with water, and they hold back oil and gas by capillary forces.
Hydrocarbons are lighter than water. At the top of an accumulation their pressure exceeds the water pressure by an amount that grows with height: $\Delta p_b = (\rho_w - \rho_h)\,g\,h$ .
The seal holds the accumulation as long as this excess is smaller than its entry pressure. The height it holds is inversely proportional to the radius of the pore throats of the seal (the narrow passages between its pores): the narrower the throats, the taller the accumulation it holds. The same seal usually holds a lower gas accumulation than an oil accumulation.
Besides capillary breakthrough, a seal can be destroyed by hydraulic fracturing (cracking under high pore pressure) and by faults (cracks along which the rock has slipped). The height of an accumulation is limited by whichever mechanism acts first.

Key relationships

p_d = \dfrac{2\sigma\cos\theta}{r}

entry pressure of a pore channel of radius $r$

\Delta p_b = (\rho_w - \rho_h)\,g\,h

excess pressure of the hydrocarbons at height $h$ above the free water level

H_{max} = \dfrac{p_{d,s} - p_{d,r}}{(\rho_w - \rho_h)\,g}

height of accumulation above the contact that the seal will hold

Common pitfalls

Treating the seal as impermeable: it lets water through, and the capillary barrier holds back the oil and gas.
Leaving the interfacial tension or the density difference out of the formula for the height of the accumulation: the result then has the wrong units.
Using the height held for oil for a gas accumulation.
Mixing up the maturity of a sandstone (in texture and in minerals) with the thermal maturity of a source rock.

After this lesson you can

explain why a reservoir needs both porosity and permeability, and what cut-offs are (limits below which a rock is not counted as a reservoir)
list the depositional and post-depositional factors of reservoir quality (what acts when the rock is laid down, and what acts afterwards), and explain why quality can be predicted from depositional environments
name the main types of seals and explain how capillary forces hold hydrocarbons back
calculate the height of an oil or gas accumulation that a seal will hold, from the size of its pore throats (the narrow passages between pores) or from mercury injection data (a laboratory test in which mercury is forced into a rock sample)
tell capillary breakthrough of a seal from hydraulic fracturing and from leakage along faults, and understand which mechanism limits an accumulation in a given case

What makes a rock a reservoir

A reservoir needs two properties at once. Porosity (Porosity), the share of voids in the rock, sets how much oil and gas fit into a trap. Permeability (Rock permeability), the ability of connected voids to let a fluid pass, sets how fast we can produce them. Oil in a rock with isolated or too narrow pores is a discovery without production. The well found it, but the inflow will not pay for development.

At the exploration stage we usually predict porosity. It is easier to estimate from analogues, from the core of neighbouring wells and from seismic data, and in many reservoirs it is closely linked to permeability. So we use rough cut-offs, which are limits below which we do not count a rock as a reservoir. For oil, it is often assumed that a rock with porosity below about 10% and permeability below about 1 mD (millidarcy, a unit of permeability) will not give a commercial flow. For gas, whose viscosity is tens of times lower, the limit is lower. Such limits are economic, not physical. They move with prices and technology. Horizontal wells and hydraulic fracturing (pumping fluid at high pressure to crack the rock) have turned rocks that were once thought too tight (not permeable enough) into reservoirs (Volumetric estimation of hydrocarbons in place).

Main types of reservoirs

Type: Clastic: sands, sandstones, siltstones
Voids: pores between grains
What decides quality: size and sorting of the grains, shale volume (the share of shale in the rock), compaction and cement

Type: Carbonate: limestones, dolomites
Voids: pores between grains, dissolution vugs, fractures
What decides quality: the original structure and especially secondary processes: dissolution, dolomitization, cementation

Type: Fractured tight rocks, weathered basement
Voids: fractures, leached zones
What decides quality: density, opening and connection of the fractures

Type	Voids	What decides quality
Clastic: sands, sandstones, siltstones	pores between grains	size and sorting of the grains, shale volume (the share of shale in the rock), compaction and cement
Carbonate: limestones, dolomites	pores between grains, dissolution vugs, fractures	the original structure and especially secondary processes: dissolution, dolomitization, cementation
Fractured tight rocks, weathered basement	fractures, leached zones	density, opening and connection of the fractures

This is only an outline: one layer may combine several types of voids.

Where reservoir quality comes from

The quality of a clastic reservoir is largely set already when the sediment is deposited. A strong current carries off the fine particles and leaves coarse, well-sorted sand. Where the flow weakens, everything settles together, mixed with mud. So if we reconstruct the depositional environments (channels, beaches and bars, deltas, submarine fans), we can predict where the reservoir is better and where there is none (Coastal, shallow-marine and deep-marine environments, Continental environments: aeolian and fluvial). After burial the rock goes on changing. This is diagenesis: the rock is compacted, cemented and partly dissolved.

How the main factors change the porosity and permeability of a sandstone

Factor: Larger grains, same sorting
Porosity: hardly changes
Permeability: grows about as the square of the grain size: the channels are wider

Factor: Poorer sorting
Porosity: falls: small grains and clay fill the gaps
Permeability: falls more than porosity

Factor: Grains laid down by a current; laminae and cross-bedding
Porosity: changes little
Permeability: larger along the layers and along the palaeocurrent (the direction of the ancient current) than across them (anisotropy)

Factor: Many feldspars and rock fragments
Porosity: falls with burial: the grains turn into clay minerals and cement
Permeability: falls, often strongly

Factor: Compaction during burial
Porosity: falls; faster in clays than in sands
Permeability: falls

Factor: Cement: quartz, calcite, clay minerals
Porosity: falls; a little early cement strengthens the framework and slows compaction
Permeability: falls: the channels narrow

Factor: Dissolution of grains and cement
Porosity: grows: secondary porosity
Permeability: grows, if the new voids are connected

Factor	Porosity	Permeability
Larger grains, same sorting	hardly changes	grows about as the square of the grain size: the channels are wider
Poorer sorting	falls: small grains and clay fill the gaps	falls more than porosity
Grains laid down by a current; laminae and cross-bedding	changes little	larger along the layers and along the palaeocurrent (the direction of the ancient current) than across them (anisotropy)
Many feldspars and rock fragments	falls with burial: the grains turn into clay minerals and cement	falls, often strongly
Compaction during burial	falls; faster in clays than in sands	falls
Cement: quartz, calcite, clay minerals	falls; a little early cement strengthens the framework and slows compaction	falls: the channels narrow
Dissolution of grains and cement	grows: secondary porosity	grows, if the new voids are connected

These are typical tendencies, not laws. For example, burrowing animals mix the sediment. Sometimes they mix in clay and make the rock worse, and sometimes they leave permeable burrows.

In carbonates, the original porosity is set by the type of grains and by how much limy mud lies between them. But the changes after deposition (secondary porosity) are usually decisive. They include the dissolving of unstable aragonite and its change into calcite, dolomitization, leached vugs and fractures. So it is harder to predict the quality of a carbonate reservoir from the depositional environment than that of a clastic one.

As a result, porosity usually, but not always, falls with depth. The exceptions are zones of secondary porosity and of early cement, and layers with abnormally high pore pressure. This pressure lowers the effective stress (the stress carried by the rock framework) and slows compaction (Diagenesis: compaction, cementation and dissolution, Abnormal formation pressures: origin, prediction and recognition).

At the exploration stage we build palaeogeographic maps (maps of the ancient geography) for chosen moments of geological time: where the sea was, where there was a delta or a river plain. They show the depocentres, where the greatest thicknesses collected, and the limits of extent of the reservoir. These maps are the basis for the map of the “reservoir” element when we assess a play (Petroleum system and the play concept). We do not usually assess variation inside the layer at this stage. That is done during development (Reservoir architecture and performance).

Seals: which rocks hold an accumulation back

Hydrocarbons are lighter than water and tend to rise. If there is no barrier above the reservoir, they rise to the surface, and this is how natural seeps of oil and gas arise. A seal is a fine-grained rock that stops this rise. Most often these are clay-rich rocks: clays, shales (argillites) and clayey siltstones. The most reliable seals are rock salt and anhydrite. Tight carbonates and cemented zones also occur.

Types of seals

Rock: Rock salt, anhydrite
What is good about it: almost no pores; salt is plastic: when deformed it flows instead of cracking
Weak points: salt dissolves in water and is itself mobile: where it has been squeezed into domes, “windows” are left in the seal; anhydrite can be brittle

Rock: Clays, shales (argillites)
What is good about it: very small pores, so a high entry pressure; the most widespread
Weak points: when strongly compacted they become brittle and crack; faults

Rock: Siltstones, clayey sandstones
What is good about it: can hold small accumulations
Weak points: the channels are larger, so the height they hold is small

Rock: Tight carbonates, cemented zones
What is good about it: low porosity
Weak points: brittle: fractures turn them from a seal into a reservoir

Rock	What is good about it	Weak points
Rock salt, anhydrite	almost no pores; salt is plastic: when deformed it flows instead of cracking	salt dissolves in water and is itself mobile: where it has been squeezed into domes, “windows” are left in the seal; anhydrite can be brittle
Clays, shales (argillites)	very small pores, so a high entry pressure; the most widespread	when strongly compacted they become brittle and crack; faults
Siltstones, clayey sandstones	can hold small accumulations	the channels are larger, so the height they hold is small
Tight carbonates, cemented zones	low porosity	brittle: fractures turn them from a seal into a reservoir

Seals can be regional. A regional seal covers a whole play and sets its limits, like the Lower Permian salt of the Pre-Caspian Basin. Or they can be local, covering a single trap. Not only the properties of the rock matter but also its continuity. One fault, one sandy layer or one erosion surface is enough for an accumulation to lose its seal.

The capillary barrier: entry pressure against buoyancy

The pores of a seal are filled with water, and the rock is wet by water. For oil or gas to enter a water-filled channel, the boundary between hydrocarbon and water must be pushed through its narrowest place. For this, the pressure in the hydrocarbon must exceed the pressure in the water by the capillary pressure of this channel (Capillary pressure and the transition zone). The narrower the channel, the larger the pressure difference needed. The threshold value of this difference is called the entry pressure (also the threshold pressure). A similar measure is the breakthrough pressure: the pressure at which hydrocarbons pass right through a rock sample.

Entry pressure of a pore channel

p_d = \frac{2\sigma\cos\theta}{r}

where:

$p_d$ entry pressure: the excess of the hydrocarbon pressure over the water pressure at which the boundary between the hydrocarbon and the water passes through the narrowest point of the channel, Pa
$\sigma$ interfacial tension between the hydrocarbon and water (how strongly the boundary between the two fluids pulls on itself), N/m
$\theta$ contact angle (the angle at which the boundary between the fluids meets the rock surface), measured through the water; close to zero for a water-wet rock (one whose surface prefers water), °
$r$ radius of the narrowest point of the pore channel, m

Units: SI

Holds when

The channel is modelled as a cylinder. For a real rock, $r$ is the effective radius of the largest channels that form a connected path through the seal.
The rock is water-wet ( $\theta < 90^\circ$ ). In an oil-wet rock (one whose surface prefers oil) there is no capillary barrier for oil (Wettability and interfacial phenomena).
Take $\sigma$ and $\theta$ at reservoir pressure and temperature.

If the channel radius is 10 times smaller, the entry pressure is 10 times higher. For an oil–water pair with $\sigma = 0.025$ N/m, a channel of 1 µm radius lets oil through at 50 kPa, while a channel of 10 nm radius lets it through only at 5 MPa.

Now let us look at what presses on the seal. In an accumulation connected to the water-bearing part of the layer (the aquifer), the pressures of oil and water are equal at the free water level (FWL). Above it, the pressure in the oil falls with height more slowly than the pressure in the water, because oil is lighter. With each metre of rise, the oil column loses $\rho_o g$ and the water column loses $\rho_w g$ . So at a height $h$ above the FWL, the oil presses on the water in the pores with an excess of $(\rho_w - \rho_o)\,g\,h$ . This is the same capillary pressure that decides the saturation of the accumulation with height (Fluid saturation). At the top of the accumulation the excess is greatest, and it presses the oil against the seal.

Excess pressure of rising hydrocarbons (buoyancy)

\Delta p_b = (\rho_w - \rho_h)\,g\,h

where:

$\Delta p_b$ excess of the hydrocarbon pressure over the water pressure at the same depth, Pa
$\rho_w,\ \rho_h$ densities of formation water and of the hydrocarbon (oil $\rho_o$ or gas $\rho_g$ ) at reservoir conditions, kg/m³
$g$ acceleration of gravity, 9.81, m/s²
$h$ height above the free water level, m

Units: SI

Holds when

The water in the layer is at rest (hydrostatics). When formation waters move, the contact tilts (Traps and timing).
The column of hydrocarbons is continuous and connected to the water-bearing part of the layer.
Densities are constant over the height of the accumulation.

The excess grows linearly with height. With a density difference of 350 kg/m³ (oil), this is about 3.4 kPa per metre. With 900 kg/m³ (gas), it is about 8.8 kPa per metre. Gas presses on the seal about 2.6 times harder.

In other unit systems (2)

Metric oilfield units

\Delta p_b\,[\text{MPa}] = 0.00981\,(\rho_w - \rho_h)\,[\text{g/cm}^3]\;h\,[\text{m}]

densities in g/cm³, height in m, pressure in MPa.

$0.00981$ MPa is the pressure of a column 1 m high at a density of 1 g/cm³ ( $1000\cdot 9.81$ Pa).

Oilfield units

\Delta p_b\,[\text{psi}] = 0.433\,(\gamma_w - \gamma_h)\;h\,[\text{ft}]

$\gamma_w,\ \gamma_h$ are relative densities (against fresh water), $h$ is in feet, pressure in psi.

$0.433$ psi/ft is the pressure gradient of a column of fresh water.

The seal holds the accumulation as long as the excess pressure at its top is smaller than its entry pressure. But inside the reservoir too, the oil does not fill the pores from the FWL. It starts from the height at which the excess reaches the entry pressure of the reservoir. There the oil–water contact (OWC) lies. If we set the excess at the top equal to the entry pressure of the seal, and measure the height from the OWC, we get the height of accumulation that the seal can hold.

Height of accumulation that the seal will hold

H_{max} = \frac{p_{d,s} - p_{d,r}}{(\rho_w - \rho_h)\,g} = \frac{2\sigma\cos\theta\left(\dfrac{1}{r_s} - \dfrac{1}{r_r}\right)}{(\rho_w - \rho_h)\,g}

where:

$H_{max}$ greatest height of the column of hydrocarbons from the contact (oil–water, OWC, or gas–water, GWC) to the top under the seal, m
$p_{d,s},\ p_{d,r}$ entry pressures of the seal and of the reservoir, Pa
$r_s,\ r_r$ effective radii of the pore channels of the seal and of the reservoir, m
$\sigma,\ \theta$ interfacial tension and contact angle, as in the formula for entry pressure, N/m, °
$\rho_w,\ \rho_h,\ g$ as in the buoyancy formula, kg/m³, m/s²

Units: SI

Holds when

The water is at rest. The seal is continuous, with no fractures or conducting faults.
The height is measured from the contact. Measured from the free water level, the height held is larger by $p_{d,r}/[(\rho_w - \rho_h)\,g]$ .
The effective radius is the radius of the largest connected channels of the seal. Leakage follows the easiest path, not the average pore size.
All properties are taken at reservoir conditions.

The height is inversely proportional to the radius of the channels of the seal and to the density difference. The channels of the seal are orders of magnitude narrower than those of the reservoir. So the second term in the brackets is usually small, and $H_{max} \approx 2\sigma\cos\theta/[r_s(\rho_w - \rho_h)\,g]$ . The interfacial tension must stand in the numerator, and the density difference in the denominator. Without them the formula gives the wrong units, which is a handy check.

CalculatedExcess pressure of oil and gas over the water pressure against the height above the contact, for the data of the example below. The lines start at the entry pressure of the reservoir and grow with the slope

(\rho_w - \rho_h)\,g

. The seal holds the accumulation up to the height at which the line reaches its entry pressure (500 kPa for oil and 1000 kPa for gas).

Worked exampleWhich accumulation a siltstone seal will hold

Given (assumed data)

Effective radius of the channels of the seal $r_s$: 0.1 µm (siltstone)
Radius of the channels of the reservoir $r_r$: 10 µm (sandstone)
Interfacial tension at reservoir conditions: oil–water 0.025 N/m, gas–water 0.050 N/m
Contact angle: $\theta = 0$ : the seal is water-wet, $\cos\theta = 1$
Densities at reservoir conditions: water 1100, oil 750, gas 200 kg/m³

Solution

Entry pressure for oil: for the seal $p_{d,s} = 2\cdot 0.025/(0.1\cdot10^{-6}) = 500$ kPa, and for the reservoir $p_{d,r} = 2\cdot 0.025/(10\cdot10^{-6}) = 5$ kPa.
The excess pressure of the oil grows by $(1100 - 750)\cdot 9.81 = 3434$ Pa per metre of height.
Height of the oil accumulation above the OWC: $H = (500 - 5)\cdot 10^3/3434 = 144$ m.
For gas: $p_{d,s} = 1000$ kPa and $p_{d,r} = 10$ kPa. The growth is $(1100 - 200)\cdot 9.81 = 8829$ Pa/m, and $H = (1000 - 10)\cdot 10^3/8829 = 112$ m.

Answer: The seal will hold about 144 m of oil or about 112 m of gas above the contact.

What it means. Gas has twice the interfacial tension, so its entry pressure is higher. But its buoyancy grows with height 2.6 times faster, and the gas accumulation comes out lower. If the seal were a clay with channels of 0.01 µm, the entry pressure would be 10 times higher, and the height of oil held would be about 1455 m. That is more than the closure of almost any trap (the height of a trap from its top to its spill point). So under clay seals the height of an accumulation is more often limited by spilling (the trap is full and overflows), by the supply of hydrocarbons or by hydraulic fracturing than by capillary forces. The data in this example are assumed for illustration.

CalculatedHeight of accumulation that the seal holds, against the effective radius of the channels of the seal, for oil and gas with the properties of the example (logarithmic scales). The point is the siltstone seal of the example. The rock names are approximate.

How a seal loses its tightness

Capillary breakthrough is not the only mechanism. A seal can lose its tightness in several ways, and the height of the accumulation is limited by the one that acts first.

Capillary breakthrough: When the column grows to the height the seal can hold, hydrocarbons enter the seal and slowly seep upwards. The height of the accumulation stays near the limit, and the excess leaks away. Seals that leak in this way are sometimes called membrane seals.
Hydraulic fracturing of the seal: The fracture pressure of the seal is close to the minimum horizontal stress in it (the smallest sideways squeeze on the rock). If the pressure of the hydrocarbons at the top exceeds it, fractures open, whatever the size of the pores. This is typical for zones of abnormally high pore pressure, where the margin before fracturing is small (Abnormal formation pressures: origin, prediction and recognition, Fracture gradient and leak-off testing).
Faults: A fault can put the reservoir against permeable rocks, or it can open during new movements. And the reverse: a fault zone filled with clayey material becomes a barrier itself (Faults).
Slow losses: Over millions of years, gas diffuses through the water in the pores of the seal. Accumulations are also destroyed when the seal is uplifted and eroded, and when the layers tilt and carry the oil out of the trap.

Thick clay seals with channels a few or a few tens of nanometres wide hold hundreds of metres of oil by capillary forces. This is more than the closure of most traps. Then the height of the accumulation is limited by the spill point, by the amount of hydrocarbons that arrived, or by hydraulic fracturing (Traps and timing). The capillary limit decides when the seal is a siltstone or a clayey sandstone, as in the example above.

Terms and symbols

Reservoir rock: A rock that can hold oil and gas and give them up during production: it is porous and permeable.
Seal (caprock): A rock of low permeability above the reservoir that holds hydrocarbons back by capillary forces.
Entry pressure $p_d$: The excess of the hydrocarbon pressure over the water pressure at which the hydrocarbon starts to enter the largest connected channels of the rock.
Buoyancy pressure $\Delta p_b$: The excess of the hydrocarbon pressure over the water pressure. It grows with the height above the free water level.
Seal capacity $H_{max}$: The greatest height of an accumulation that the seal holds by capillary forces.
Cut-offs: Limits of porosity, permeability and saturation below which a rock is not counted as a reservoir.
Secondary porosity: Voids that formed after deposition: dissolution vugs, fractures, pores of dolomitization.
Textural maturity: The degree of sorting and rounding of sand. Richness in stable quartz is called compositional maturity.

Common mistakes and misconceptions

Wrong

“A seal is an impermeable rock.”

In fact

A seal is permeable to water, though very weakly. It holds oil and gas back by a capillary barrier: the excess pressure of the hydrocarbons is not enough to push the boundary with the water through the narrow channels.

Wrong

“The thicker the seal, the taller an accumulation it holds.”

In fact

The capillary holding capacity is set by the size of the channels, not by the thickness. Thickness matters for continuity: a thin seal is easier to break through with a fault, or to erode.

Wrong

“If the seal holds 150 m of oil, it will hold as much gas.”

In fact

The density difference between water and gas is usually 2–3 times larger than between water and oil. Even with the larger interfacial tension, a gas accumulation under the same seal is, as a rule, lower. We calculate the height held separately for each fluid.

Wrong

“We found oil, so we found a reservoir.”

In fact

A reservoir must also give up the oil. With porosity and permeability below the cut-offs, the discovery may prove non-commercial.

Wrong

“The height of an accumulation from the OWC equals the entry pressure of the seal divided by the buoyancy of one metre.”

In fact

That gives the height above the free water level. From the OWC the height is smaller by an amount that corresponds to the entry pressure of the reservoir. This is why $p_{d,r}$ is subtracted in the formula.

In depth: advanced detail

Entry pressure from mercury injection

We cannot measure the channel radius of a seal with a ruler. We find it by mercury injection capillary pressure (MICP). We take a dried sample of the seal (a core, or large cuttings, which are chips of rock brought up by the drilling mud) and pump the air out of it. Then we force mercury into it in steps of pressure. Mercury is a non-wetting liquid: it does not stick to the rock, so it enters the pores only under pressure. We record the pressure at which the mercury starts to fill the connected system of channels. Then we convert the laboratory entry pressure to the pair of fluids in the reservoir, in proportion to the product $\sigma\cos\theta$ . We do the same for the whole capillary pressure curve (Capillary pressure and the transition zone).

Converting entry pressure from mercury to reservoir fluids

p_{d,\text{res}} = p_{d,\text{Hg}}\,\frac{(\sigma\cos\theta)_{\text{res}}}{|\sigma\cos\theta|_{\text{Hg}}},\qquad r = \frac{2\,|\sigma\cos\theta|_{\text{Hg}}}{p_{d,\text{Hg}}}

where:

$p_{d,\text{Hg}}$ entry pressure of mercury, measured on the sample, Pa
$p_{d,\text{res}}$ entry pressure for the hydrocarbon–water pair in the reservoir, Pa
$|\sigma\cos\theta|_{\text{Hg}}$ for mercury in an evacuated sample we usually take $\sigma \approx 0.485$ N/m and $\theta \approx 140^\circ$ (measured through the mercury), that is about 0.372 N/m, N/m
$(\sigma\cos\theta)_{\text{res}}$ the same for the reservoir pair of fluids, N/m
$r$ equivalent radius of the channels, m

Units: SI (or any consistent units of pressure)

Holds when

The channels are modelled as cylinders, and the geometry of the pores is the same for mercury and for reservoir fluids.
The contact angle of mercury is measured through the mercury, so we take the modulus of the cosine.
The sample is representative. Without the load of the surrounding rock, its channels may be wider than in the reservoir.

For an oil–water pair with $\sigma\cos\theta \approx 0.025$ N/m, the entry pressure is about 15 times lower than the mercury one.

Worked exampleHeight held, from mercury injection

Given (assumed data)

Entry pressure of mercury into the sample of the seal: 12 MPa
Mercury–vacuum: $\sigma = 0.485$ N/m, $\theta = 140^\circ$ through the mercury
Oil–water in the reservoir: $\sigma = 0.025$ N/m, $\theta = 0$
Buoyancy of the oil and entry pressure of the reservoir: 3434 Pa/m and 5 kPa (as in the example above)

Solution

For mercury, $|\sigma\cos\theta| = 0.485\cdot|\cos 140^\circ| = 0.372$ N/m. The equivalent radius of the channels is $r = 2\cdot 0.372/(12\cdot10^6) = 62$ nm.
Entry pressure for oil: $p_{d,s} = 12\cdot 0.025/0.372 = 0.81$ MPa.
Height held above the OWC: $H = (807 - 5)\cdot 10^3/3434 = 234$ m.

Answer: A seal with this entry pressure of mercury will hold about 234 m of oil.

What it means. Converting by the ratio of $\sigma\cos\theta$ is the standard way to carry laboratory data into the reservoir. The main uncertainties are the interfacial tension and the wettability in the reservoir, and how representative the sample is. One fracture or sandy layer in the seal matters more than many measurements on tight samples. The data in this example are assumed for illustration.

When fracturing of the seal limits the accumulation

The pressure of the hydrocarbons at the top is the sum of the water pressure at this depth and the buoyancy excess. If we know the fracture pressure of the seal at this depth, we can estimate the greatest height of the accumulation by this mechanism:

Height of accumulation limited by fracturing of the seal

H_{frac} = \frac{p_{frac} - p_w}{(\rho_w - \rho_h)\,g}

where:

$H_{frac}$ height above the free water level at which the pressure of the hydrocarbons at the top reaches the fracture pressure of the seal, m
$p_{frac}$ fracture pressure of the seal at the depth of the top, close to the minimum horizontal stress, Pa
$p_w$ formation water pressure at the depth of the top, Pa
$\rho_w,\ \rho_h,\ g$ as in the buoyancy formula, kg/m³, m/s²

Units: SI

Holds when

The pressures are taken at the depth of the top of the accumulation. $p_w$ is the water pressure continued along the gradient of the water-bearing part of the layer.
The seal opens when the pressure in it exceeds the fracture pressure. We ignore its tensile strength (how well the rock resists being pulled apart).
The estimate is rough: the fracture pressure of the seal is known with a considerable error.

At normal pore pressure, the margin $p_{frac} - p_w$ is many megapascals, and this mechanism does not limit the accumulation. In zones of abnormally high pressure the margin shrinks to a few megapascals, and the fracturing limit becomes the main one, especially for gas.

Worked exampleAn accumulation under a seal in a zone of abnormally high pressure

Given (assumed data)

Depth of the top: 3000 m
Formation water pressure at this depth: 58.5 MPa
Fracture pressure of the seal: 60.0 MPa
Densities at reservoir conditions: water 1100, oil 750, gas 200 kg/m³

Solution

The margin before fracturing is $60.0 - 58.5 = 1.5$ MPa.
Oil: $H = 1.5\cdot10^6/(350\cdot 9.81) = 437$ m. Gas: $H = 1.5\cdot10^6/(900\cdot 9.81) = 170$ m.
For comparison, at hydrostatic pressure (water of density 1100 kg/m³) the pressure at this depth would be only 32.4 MPa. So the layer is under abnormally high pressure, and the margin before fracturing is small.

Answer: Fracturing will limit the accumulation to about 437 m of oil or 170 m of gas above the free water level, even if the seal would hold more by capillary forces.

What it means. A clay seal with channels of about 10 nm would hold more than a thousand metres of oil by capillary forces (see the example in the section on the capillary barrier). But at this pressure, fracturing acts first. So in basins with strong abnormally high pressure, traps are often not filled to the spill point, and gas accumulations are especially low. The data in this example are assumed for illustration.

Connections to other topics

Petroleum system and the play concept — the reservoir and the seal as elements of the petroleum system and of the play.
Traps and timing — what else limits the height of an accumulation: closure of the trap, spilling and the supply of hydrocarbons.
Capillary pressure and the transition zone — capillary pressure, entry pressure and the conversion of laboratory curves.
Wettability and interfacial phenomena — why a seal holds oil only if it is wet by water.
Fluid saturation — how saturation is distributed with height above the free water level.
Diagenesis: compaction, cementation and dissolution — how compaction, cementation and dissolution change the reservoir after burial.
Fracture gradient and leak-off testing — the fracture pressure of rocks and how it is found.
Volumetric estimation of hydrocarbons in place — how the reservoir, the cut-offs and the height of the accumulation enter the calculation of hydrocarbons in place.

Check yourself

1
Which rock is usually the most reliable regional seal?
1. A.Rock salt
2. B.Coarse-grained sandstone
3. C.Siltstone with sandy layers
4. D.Fractured limestone
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Correct answer: A. Rock salt
Salt has almost no pores, and when it is deformed it flows instead of cracking. So cracks and faults in it quickly “heal”. Fractured limestone and sandstone are more likely to be reservoirs. A siltstone with sandy layers will hold only a small accumulation.
2
The seal is a shale (argillite) with an effective channel radius of 0.05 µm. The oil–water interfacial tension is 0.03 N/m, the contact angle is 0, and the density difference between water and oil is 300 kg/m³. What height of oil accumulation will the seal hold, if we neglect the entry pressure of the reservoir?
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$p_d = 2\cdot 0.03/(0.05\cdot10^{-6}) = 1.2$ MPa; $H = 1.2\cdot10^6/(300\cdot 9.81) \approx 408$ m. Most likely this accumulation will be limited not by the seal but by the closure of the trap or by the amount of oil that arrived.
3
The same seal covers two neighbouring traps: one with oil and one with gas. Where is the height held smaller?
1. A.It depends only on the thickness of the seal
2. B.In the oil trap
3. C.The same
4. D.In the gas trap
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Correct answer: D. In the gas trap
The buoyancy of gas grows with height 2–3 times faster than that of oil, because its density difference from water is larger. The larger gas–water interfacial tension raises the entry pressure, but it usually does not make up for this fully.
4
Why can a 20 m layer of clay hold hundreds of metres of oil, while a 200 m sequence of clayey siltstones holds only tens?
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The capillary holding capacity is set by the size of the largest connected channels, not by the thickness. In a clay the channels are nanometres wide, and in a siltstone they are tenths of a micrometre. So the entry pressures differ by an order of magnitude or more. Thickness matters for continuity: a thin seal is easier to break through with a fault.
5
An exploration well found oil in a limestone with porosity of 6% and permeability of 0.05 mD, with no fractures. How should we judge this?
1. A.An excellent reservoir
2. B.It is a seal, and there cannot be oil in it
3. C.Most likely a non-commercial reservoir: porosity and permeability are below the usual cut-offs; a test and an assessment of stimulation methods are needed
4. D.It is a source rock
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Correct answer: C. Most likely a non-commercial reservoir: porosity and permeability are below the usual cut-offs; a test and an assessment of stimulation methods are needed
There is oil in the rock, but with this permeability a commercial flow without stimulation is unlikely. Cut-offs are economic: hydraulic fracturing or horizontal wells may change the conclusion. So the decision is made from the test and the economics.
6
How does the textural maturity of a sandstone differ from the thermal maturity of a source rock?
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Textural maturity describes the sand itself: its sorting and rounding (the share of stable quartz is described by compositional maturity). Both affect reservoir quality. Thermal maturity describes how far the organic matter of the source rock has been heated, and how much oil and gas it has already made.

Updated: 30 September 2026