Traps and timing · MunaiHub

Quick refresher

A trap is a reservoir, a seal and a geometry that leaves rising hydrocarbons nowhere to go.
Closure is the vertical distance from the crest (the highest point of the trap) to the spill point (the lowest point where the trap still holds hydrocarbons). The height of an accumulation is limited by the tightest of three limits: the closure, the seal capacity (how tall a column of hydrocarbons the seal can hold) and the amount of hydrocarbons that arrived.
Deformation of the rocks creates structural traps: folds, faults, salt movement. They are younger than the host rocks. Stratigraphic traps come from the conditions when the rocks were deposited, or from later changes in the rocks, and they often exist from the very beginning.
Moving formation water tilts the contact in the direction of flow. The tilt of the contact is $\rho_w/(\rho_w - \rho_o)$ times steeper than the tilt of the potentiometric surface (the level to which the water would rise in wells).
The trap must exist by the time of migration. A burial history curve (a plot of how deep a rock was buried through geological time) with a temperature scale shows when the source rock was in the generation zone. We compare the times when the traps formed with this interval.
Late tilting of the beds can empty old traps and fill new ones (remigration). When hydrocarbons spill along a chain of traps, gas stays in the traps nearest the kitchen (the area where the source rock makes hydrocarbons), and oil goes on to the farther ones.

Key relationships

Z = z_{\text{spill}} - z_{\text{crest}}

closure: the depth of the spill point minus the depth of the crest

H \le \min\left(Z,\ H_{max},\ H_{\text{charge}}\right)

the height of an accumulation is no greater than the smallest of the closure, the seal capacity and what the charge supplied

\dfrac{\dd z_c}{\dd x} = \dfrac{\rho_w}{\rho_w - \rho_o}\,\dfrac{\dd h}{\dd x}

tilt of the oil–water contact under moving formation water. Here $z_c$ (the contact) and $h$ (the head, the water pressure expressed as a height) are elevations measured upwards, not depths like $z$ in the other formulas

T = T_0 + G_T\,z

temperature at a depth $z$ for a constant geothermal gradient $G_T$

Common pitfalls

Assuming that every mapped trap is filled to its spill point.
Forgetting about time: a structure that grew after migration may be empty.
Drawing a horizontal contact where formation waters are moving: the contact is tilted, and moving water may have flushed the oil out of part of the trap.
Thinking that a pinch-out trap or a trap beneath an unconformity needs no structure: without dip of the beds (their slope) it does not work.

After this lesson you can

identify the elements of a trap (crest, closure, spill point) and understand what limits the height of an accumulation: spill, seal or charge
tell structural, stratigraphic, combination and hydrodynamic traps (held in place by flowing formation water) apart, and recognise them on schematic cross-sections
estimate how much the oil–water contact tilts when formation water is moving
explain why a trap must be older than the migration, and how spilling from one trap to the next, and remigration (a second move of oil and gas), change where oil and gas end up
draw a simple burial history curve with a break (a pause in burial) and an uplift, and use it to find which traps were in place in time to receive oil

Anatomy of a trap: crest, closure, spill point

Oil and gas are lighter than water. After they leave the source rock, they rise along permeable beds (beds that let fluids through) under seals (Petroleum system and the play concept). A trap is the place where the rise stops. The top of the reservoir forms an “inverted bowl”, and the hydrocarbons have nowhere to go upwards. Several elements describe a trap.

Crest: the highest point of the top of the reservoir in the trap; the accumulation begins here.
Spill point: the lowest point at which the trap can still retain hydrocarbons: a saddle (a low point between two highs) on the way to a neighbouring structure, the end of a fault, or the edge of a pinch-out. The structure contour (a line of equal depth on the top of the reservoir) that passes through it is the last closing contour.
Closure: the vertical distance from the crest to the spill point; in Russian-language practice, the amplitude of the trap. The area inside the closing contour is the area of the trap.
Fill to spill: so many hydrocarbons have arrived that they fill the trap down to the spill point. The excess escapes through that point and goes further up the bed.

SchematicAn anticlinal trap (a trap in an arch-shaped fold) in cross-section and in plan view (seen from above): the crest, the spill point in the saddle, the closure

Z

and an accumulation of height

H

that does not fill the trap completely. If the trap were overfilled, the oil would escape through the saddle, up the dip of the bed (uphill along the sloping bed). The schematic is not to scale.

How many hydrocarbons end up in the trap depends on the tightest of three limits:

the closure: the accumulation cannot extend beyond the spill point, so it cannot be taller than the closure
the seal capacity: if the seal leaks hydrocarbons earlier, the accumulation is smaller than the closure (Reservoir and seal)
the charge: how many hydrocarbons arrived after the trap formed, minus losses

So before drilling, the position of the contact is given as a range: from “filled to spill” to “limited by the seal or the charge”. This is one of the biggest uncertainties in estimating the resources of a prospect. It matters even more because the trap holds more volume at some heights than at others.

Worked exampleA trap that is not filled to spill

Given (assumed data)

Depth of the crest at the top of the reservoir: 2150 m
Depth of the spill point: 2270 m
Area inside the closing contour $A_s$: 12 km²
Seal capacity: 85 m of oil (the tallest oil column the seal can hold)
Oil supplied: more than enough
Shape of the trap: a dome: the area inside a contour grows in proportion to the depth below the crest; the reservoir is thicker than the accumulation

Solution

Closure: $Z = 2270 - 2150 = 120$ m. The seal holds 85 m, which is less than the closure. So the seal limits the accumulation, and the oil–water contact (OWC) will settle at a depth of $2150 + 85 = 2235$ m.
At a depth $z$ below the crest, the area is $A(z) = A_s\,z/Z$ . So the volume of rock above the contact, for an accumulation of height $H$ , is $V(H) = \int_0^H A(z)\dd z = \dfrac{A_s H^2}{2Z}$ .
The whole trap: $V(Z) = 12\cdot10^6\cdot 120/2 = 720$ million m³. An accumulation 85 m high: $V = 12\cdot10^6\cdot 85^2/240 = 361$ million m³.
Fill fraction: by height, $85/120 = 0.71$ ; by volume, $(85/120)^2 = 0.50$ .

Answer: The accumulation will occupy 71% of the height of the trap but only 50% of its volume: about 361 million m³ of rock out of 720 million m³.

What it means. The lower part of the dome is wider than the upper part. So the last tens of metres of closure hold a disproportionately large share of the volume. Suppose we put the contact at the spill level, but the seal in fact limits the accumulation. Then the rock volume and the resources would be too high by a factor of two. So we calculate the resources of a prospect for several positions of the contact (Volumetric estimation of hydrocarbons in place, Gross rock volume from maps). The data in this example are assumed for illustration.

Structural traps

Structural traps are created by deformation of the rocks after they were deposited: folds, faults, salt movement and draping (beds bending over buried highs). So they are always younger than the host rocks, and they may turn out to be younger than the migration.

SchematicThe main types of traps in schematic cross-sections. On the left are structural traps (anticlinal, fault-bounded, at a salt dome). On the right are stratigraphic traps (pinch-out of a bed, beneath an unconformity, reef). Oil is shown in orange. The schematics are not to scale.

Anticlinal (crestal) trap: a fold closed on all sides by the dip of the beds (four-way closure). It is the easiest to map and historically the most common type. Folds form under compression (squeezing), over salt domes, and where beds drape over buried highs and reefs (Folds, salt diapirs and their relationship to faults).
Fault-bounded (tectonically screened) trap: a bed that rises towards a fault is closed by dip on three sides and by the fault on the fourth (three-way closure). It works only if the fault itself acts as a seal: either the reservoir meets shale across the fault, or the fault zone is filled with clay-rich material (Faults). It occurs at normal faults in extensional zones (where the rocks are pulled apart) and at reverse faults in compressional zones (where they are squeezed together).
Rollover anticline: a fold in the downthrown block (the block that slid down) of a curved (listric) normal fault that moved while the sediments were being deposited. Such growth faults are typical of thick delta deposits. Thicker layers build up in the downthrown block.
Traps at salt domes: salt is ductile (it flows slowly without breaking). Under the uneven load of the sediments it flows and rises, forming domes and stocks (columns): diapirs. Over a dome the beds bend into a crest. On the flanks the beds are turned up and meet the salt, which acts as a seal. There are also traps under salt “overhangs” and in blocks broken by faults above a dome. This is how many suprasalt traps (traps above the salt) of the Pre-Caspian Basin are built.

Stratigraphic and combination traps

In a stratigraphic trap, the reservoir and seal are in the right position not because of deformation, but because of the conditions when the rock was deposited or because of later changes in the rock. On a structure map such traps do not show up as “highs”, so they are harder to find. Facies maps (maps of rock types), seismic attributes (measurements taken from seismic data) and well-to-well comparison help (Seismic interpretation).

Pinch-out: a sand body gets thinner up the dip and disappears into shale: for example a coastal bar, a channel sandstone (a sand-filled river channel) or a fan-shaped sand body.
Facies change: the reservoir changes along strike (sideways, across the dip) into impermeable rock: sandstone into shale, or porous limestone into tight limestone (a lithological seal).
Diagenetic trap: porosity up the dip has been destroyed by cement (minerals that grew in the pores and filled them).
Trap beneath an unconformity: sloping beds are cut off by erosion and covered by shales that were deposited after the gap in time. The reservoir is sealed along the unconformity surface (Stratigraphy and geologic time).
Reef trap: a buried reef or other carbonate buildup (a mound of limestone built by organisms), draped by shales: the porous body stands above the surrounding rocks. In the Russian-language classification, reef traps usually form a class of their own.

Pinch-out traps and traps beneath unconformities still need structure in the broad sense. The beds must slope so that the pinching-out or cut-off end of the reservoir is higher than the rest of it. If the dip of the beds changes, the trap may open up. A reef or a sand lens (a lens-shaped sand body) with shale on all sides is closed by its own shape.

Where the reservoir changes into the seal gradually, a strip of poor rock lies between them. Hydrocarbons enter it, but they can hardly be recovered. When we estimate hydrocarbons in place, we cut such zones off with cutoff values, the minimum rock quality that is counted (Volumetric estimation of hydrocarbons in place).

Combination traps combine several mechanisms. For example, a sandstone pinches out on the flank of a fold, an unconformity cuts off a reservoir on the crest of an uplift, or a fault adds to a lithological seal. Many large fields are of this kind, and we assess the probability of success for each closure mechanism (Geological risk and chance of success).

Moving water and contacts

While the water in the bed is still, the oil–water contact is horizontal. But formation waters often flow slowly, from recharge areas (where the bed receives water) to discharge areas (where the water leaves the bed). Then the water pressure changes along the bed, not only with depth, and the boundary between oil and water tilts. The potentiometric surface describes the movement of the water. It is the elevation to which the water would rise in wells that penetrate the bed. Its slope sets the direction and strength of the flow.

Tilt of the oil–water contact under moving formation water

\frac{\dd z_c}{\dd x} = \frac{\rho_w}{\rho_w - \rho_o}\cdot\frac{\dd h}{\dd x}

where:

$z_c$ elevation (height) of the oil–water contact, m
$h$ head of the formation water — the elevation of the potentiometric surface, m
$x$ horizontal distance along the direction of flow, m
$\rho_w,\ \rho_o$ densities of formation water and oil in the reservoir, kg/m³

Units: any consistent system; slopes are conveniently expressed in metres per kilometre

Holds when

The water flow is steady (it does not change with time), and the oil in the trap does not move.
We ignore capillary effects, and the densities are constant.
For a gas–water contact, use the gas density $\rho_g$ instead of $\rho_o$ .

The contact tilts in the same direction as the potentiometric surface: it goes deeper in the direction of flow. But it is $\rho_w/(\rho_w - \rho_o)$ times steeper: usually 3–10 times for oil, still more for heavy oil, and only 1.2–1.3 times for gas. The derivation is in the advanced section.

Worked exampleA tilted contact in a trap with moving water

Given (assumed data)

Slope of the potentiometric surface: 1.5 m per 1 km, flow to the east
Densities in the reservoir: water 1050, oil 850, gas 200 kg/m³
Width of the trap along the flow: 4 km
Dip of the flanks of the trap: 1°, about 17.5 m per 1 km

Solution

Multiplier for oil: $\rho_w/(\rho_w - \rho_o) = 1050/(1050 - 850) = 5.25$ ; tilt of the OWC: $5.25\cdot 1.5 = 7.9$ m/km.
Across the 4 km width of the trap, the contact on the eastern flank (where the water flows to) is deeper than on the western flank by 32 m.
For gas: the multiplier is $1050/(1050 - 200) = 1.24$ , the tilt of the gas–water contact is 1.9 m/km, and the difference over 4 km is 7.4 m.
The tilt of the OWC (7.9 m/km) is less than the dip of the flanks (17.5 m/km). So the trap still holds the oil, but the accumulation is shifted downstream (in the direction of flow).

Answer: The OWC tilts by about 7.9 m/km, and across the width of the trap it goes deeper downstream by 32 m. Under the same conditions the gas–water contact tilts by only 1.9 m/km.

What it means. Heavy oils are affected most: at a density of 950 kg/m³ the multiplier would already be 10.5. If the tilt of the contact exceeds the dip of the flank, the moving water flushes the oil out from that flank. With a strong flow, a trap with a small closure may be emptied completely. If we take a tilted contact to be horizontal, we get errors in the volume of the accumulation and in the placement of wells. The data in this example are assumed for illustration.

A water flow directed down the dip of a bed can do the opposite: it can hold oil where there is no closure at all, on a structural nose (a ridge that plunges) or a terrace (a flat step on a slope). Such hydrodynamic traps are rare, but tilted contacts are common.

Contacts within one trap can also differ for other reasons:

Blocks separated by sealing faults were each filled in their own way, so each has its own contact. Different contacts are an important sign that an accumulation is divided into separate compartments for development (Partially communicating faults).
Perched contacts: water stayed above the main contact, held back by a barrier to flow or by the way the trap was filled (Perched and tilted contacts, trapped water).
Incomplete filling or leakage: the accumulation is still being filled or has partly lost its hydrocarbons, and the contact has not settled at its equilibrium level.

Timing: the trap must not be late

The main rule: the trap must exist when most of the migrating hydrocarbons pass through it. That is, it must exist by the critical moment of the petroleum system (the time when most of the system's oil and gas is generated, moves and collects; Petroleum system and the play concept). Different traps form at different times:

Stratigraphic traps created by the conditions of deposition (pinch-out, facies change, reefs) exist almost from the very beginning, and they are usually older than generation.
Traps beneath unconformities appear when a new seal covers an erosion surface, sometimes much later than the reservoir was deposited.
Structural traps form during folding and when faults and salt move. This is often late, and then the early oil goes past.

A late trap is not necessarily empty. Late generation may fill it (more often with gas, if the source rock has been buried deeper). Or remigration may fill it: late tilting of the beds empties old traps, and their oil moves into new ones. So we assess not only when the trap formed, but also how well it was preserved after filling.

Along one migration path, traps often form a chain and fill one after another. The first trap, nearest the kitchen, fills to spill and passes the excess to the next one, which lies higher up the dip. Suppose both gas and oil arrive. The gas is the lightest, so it takes the top of the first trap and pushes the oil out through the spill point and on to the next trap. As a result the nearest traps hold gas, the next ones hold oil, and the most distant ones, which the hydrocarbons did not reach, hold only water. This principle is called differential entrapment. It works when the traps are filled to spill. It also explains why an oil accumulation lying higher up the dip than a gas accumulation is not a model error.

We find the time of generation from the burial history curve (also called the geohistory curve). It shows how the depth of the source rock changed with time. We build it from the thicknesses and ages of the beds in wells and cross-sections. The rate of sedimentation is the thickness divided by the time it took to accumulate, with compaction taken into account. Breaks in sedimentation give horizontal segments. Uplift and erosion give rising segments. If we add the temperature, taken from the geothermal gradient (how fast temperature rises with depth), we can find when the rock was in the generation window.

Worked exampleA burial history curve with a break and uplift: which traps were in time

Given (assumed data)

The source rock was deposited: 120 million years ago
From 120 to 80 million years ago: burial of 50 m per 1 million years
From 80 to 60 million years ago: a break: the depth does not change
From 60 to 20 million years ago: burial of 60 m per 1 million years
The last 20 million years: uplift and erosion, 30 m per 1 million years
Temperature: 10 °C at the surface, gradient 30 °C/km, both constant
Assumed window of main oil generation: from 100 to 130 °C
Time of formation of the traps: A — 70, B — 30, C — 10 million years ago

Solution

Depth at the end of the first stage: $50\cdot 40 = 2000$ m, with a temperature of $10 + 30\cdot 2.0 = 70$ °C. During the break the rock stays at this depth.
The generation window lies at depths from $(100 - 10)/30 = 3.0$ to $(130 - 10)/30 = 4.0$ km. The rock reaches a depth of 3000 m in $(3000 - 2000)/60 = 16.7$ million years after the start of the third stage, that is, 43.3 million years ago. It reaches a depth of 4000 m 26.7 million years ago.
The greatest burial, 20 million years ago, is $2000 + 60\cdot 40 = 4400$ m, at 142 °C. After the uplift, the rock today is at a depth of 3800 m, at 124 °C.
Trap A formed before generation began. Trap B catches only the end of the window. With uniform generation (the same amount in every million years), that is $(30 - 26.7)/(43.3 - 26.7) = 0.20$ , or about 20% of the oil. Trap C formed when generation had already ended.

Answer: The main oil is generated from about 43.3 to 26.7 million years ago. Trap A receives the whole flow, B about 20% of the oil, and C only what spills over from other traps.

What it means. From 26.7 million years ago on, the rock was deeper than the window, so in this scheme it generated mainly gas, which could have gone to trap B. The uplift stopped generation. Today the temperature of 124 °C is formally inside the window. But the organic matter has already been through 142 °C, and whatever could have turned into oil at lower temperatures already has. Vitrinite reflectance in a well (explained below) will show a maturity that is too high for the present depth. From this mismatch we estimate the eroded section. The real rate of generation is not constant, and the boundaries of the window depend on the type of organic matter (Source rocks, maturation and migration). The data in this example are assumed for illustration.

CalculatedBurial history curve of the source rock from the example: burial, a break, rapid burial and uplift. The dashed lines are the assumed boundaries of the window of main oil generation (100 and 130 °C at a gradient of 30 °C/km). The points mark the times when traps A, B and C formed.

We check the burial model against vitrinite reflectance ( $R_o$ ). Vitrinite is made of particles of organic matter that came from the woody tissue of plants. When heated, the particles become more reflective, and this cannot be undone. $R_o$ records the highest temperature that the rock has been through. The oil window usually corresponds to values of roughly 0.6 to 1.3%, but the boundaries depend on the type of organic matter. If the calculated maturity disagrees with the measured one, we adjust the heat flow in the past or the thickness of the eroded rocks (Source rocks, maturation and migration).

For a prospect, we construct burial history curves at several points: in the kitchen and at the trap. Then we join points of equal maturity with lines on cross-sections and maps. This gives a filling model: which area of mature source rock feeds the trap, when it began to give off oil, and when gas. Discovered accumulations usually cluster inside or next to areas of mature source rock. Outside them there are markedly fewer successful wells. Specialised programs calculate the complex two- and three-dimensional basin models.

Terms and symbols

Trap: The part of a reservoir covered by seals, so that rising hydrocarbons cannot migrate further and collect there.
Crest: The highest point of the top of the reservoir in a trap.
Spill point: The lowest point down to which the trap holds hydrocarbons. The excess escapes through it.
Closure (trap amplitude): The vertical distance from the crest to the spill point.
Structural trap: A trap created by deformation: folds, faults, salt movement.
Stratigraphic trap: A trap created by the conditions of deposition or by changes in the rocks: pinch-out, facies change, unconformity, reef.
Hydrodynamic trap: Hydrocarbons held in place by a flow of formation water where there is no closure.
Burial history curve: A graph of the depth of a bed against time. Together with the geothermal gradient, it gives the history of the bed's temperature (also called the geohistory curve).
Remigration: The movement of hydrocarbons from destroyed or tilted traps into new ones.
Differential entrapment: How gas and oil are shared out along a chain of traps that spill: gas stays in the traps nearest the kitchen, and oil goes on to the farther ones.

Common mistakes and misconceptions

Wrong

“There is a trap on the map, so it is filled to the spill point.”

In fact

The seal and the charge of hydrocarbons also limit the height of the accumulation. Before drilling, we give the contact as a range and calculate the volume of the accumulation for several cases.

Wrong

“A pinch-out trap or a trap beneath an unconformity needs no structure.”

In fact

The beds must dip: the pinching-out or cut-off end of the reservoir must be higher than the rest of it. Late tilting can open such a trap. Only bodies with shale on all sides, such as reefs and lenses, are closed by themselves.

Wrong

“The oil–water contact is always horizontal.”

In fact

Under moving formation water it tilts in the direction of flow. In blocks separated by faults the contacts may differ. Perched contacts also occur.

Wrong

“Since the trap is older than the migration, it certainly contains oil.”

In fact

It must also lie on the migration path, have a seal that works, and have been preserved after filling. Late faults, tilting and erosion can empty it.

Wrong

“An oil accumulation higher up the dip than a gas accumulation is a model error.”

In fact

That is what happens when traps in a chain spill: gas pushes oil out of the traps nearest the kitchen into the farther ones (differential entrapment).

In depth: advanced detail

Where the formula for the tilt of the contact comes from

The oil in the trap does not move, so its pressure changes with elevation as in any still fluid (hydrostatically): $p_o = C - \rho_o g z$ , where $z$ is the elevation of the point and $C$ is a constant. We express the pressure of the moving water through the head: $p_w = \rho_w g\,(h - z)$ , where $h(x)$ is the elevation of the potentiometric surface above the point. At the contact the pressures are equal, if we ignore capillary forces: $C - \rho_o g z_c = \rho_w g\,(h - z_c)$ .

From this, $z_c = \dfrac{\rho_w h - C/g}{\rho_w - \rho_o}$ . Differentiating with respect to $x$ , we get $\dfrac{\dd z_c}{\dd x} = \dfrac{\rho_w}{\rho_w - \rho_o}\,\dfrac{\dd h}{\dd x}$ . The small density difference in the denominator turns a barely noticeable slope of the potentiometric surface into a noticeable tilt of the contact. In still water $\dd h/\dd x = 0$ , and the contact is horizontal.

Compaction and restoring thicknesses

We construct a burial history curve “backwards in time”, starting from today's section. But the present thicknesses of the beds are smaller than they were in the past. As a bed is buried, its porosity falls and the layer is squeezed, while the volume of the mineral grains hardly changes. So in a reconstruction we decompact the thicknesses (restore them to what they were before compaction).

Layer thickness at a different porosity (conservation of grain volume)

h_1\,(1 - \phi_1) = h_2\,(1 - \phi_2)

where:

$h_1,\ h_2$ thickness of the layer at two moments of time, m
$\phi_1,\ \phi_2$ mean porosity of the layer at those moments, fraction

Units: thicknesses in any identical units, porosity as a fraction

Holds when

The grain volume is conserved: cement is neither added nor dissolved.
The porosity is an average over the layer. We take it from the porosity–depth relation for the rock concerned.

A layer that is 1000 m thick today, at a mean porosity of 0.10, was $1000\cdot 0.9/0.7 \approx 1290$ m thick in the past, when its mean porosity was 0.30. So in the past the source rock beneath it lay deeper than the sum of today's thicknesses suggests, and generation began earlier than the curve without decompaction shows.

Connections to other topics

Petroleum system and the play concept — the elements of the petroleum system, the critical moment and the events chart.
Reservoir and seal — what height of accumulation the seal will hold.
Source rocks, maturation and migration — when and how much oil and gas the source rock generates, and how they migrate.
Folds, salt diapirs and their relationship to faults — folds and salt domes — the main structural traps.
Faults — when a fault seals an accumulation and when it lets hydrocarbons through.
Volumetric estimation of hydrocarbons in place — how the volume of a trap and the position of the contact turn into hydrocarbons in place.
Gross rock volume from maps — how we calculate the rock volume from structure maps and contacts.
Perched and tilted contacts, trapped water — perched and tilted contacts from pressure measurements.
Geological risk and chance of success — how we assess the probability that a trap exists and is filled.

Check yourself

1
What is the closure of a trap?
1. A.The thickness of the seal above the crest
2. B.The vertical distance from the crest to the spill point
3. C.The area of the trap on the map
4. D.The distance from the trap to the kitchen
Show the answer
Correct answer: B. The vertical distance from the crest to the spill point
Closure is the greatest possible height of an accumulation in the trap. Below the spill point, the hydrocarbons escape further up the bed. The area inside the closing contour is the area of the trap.
2
The crest of a trap is at 1800 m, the spill point at 1890 m, the seal can hold 120 m of oil, and more than enough oil has arrived. Where will the OWC be and what limits the accumulation?
Show the answer
The closure of 90 m is less than the seal capacity (120 m), and there is enough oil. So the trap is filled to spill: the OWC is at a depth of 1890 m, and the height of the accumulation is 90 m. The excess oil escapes through the spill point and goes further up the bed.
3
Which traps usually appear earliest relative to hydrocarbon generation?
1. A.Traps at faults that appeared after generation
2. B.Folds that grew during late folding
3. C.Traps created by late tilting of the beds
4. D.Stratigraphic pinch-out and facies-change traps
Show the answer
Correct answer: D. Stratigraphic pinch-out and facies-change traps
The conditions of deposition set their geometry, so they exist almost from the very beginning, long before the source rock enters the generation window. Structural traps need deformation, which often comes later.
4
The potentiometric surface of the formation water falls by 2 m for every kilometre. The water density is 1.05 g/cm³, the oil density 0.80 g/cm³. What is the tilt of the OWC and in which direction does it point?
Show the answer
The multiplier is $1.05/(1.05 - 0.80) = 4.2$ , so the tilt of the OWC is $4.2\cdot 2 = 8.4$ m per kilometre. The contact goes deeper in the direction of the water flow, that is, towards where the potentiometric surface is lower.
5
Three traps lie along a migration path from the kitchen up the bed. The one nearest the kitchen contains gas, the middle one oil, the farthest one water. How can this be explained?
Show the answer
This is differential entrapment. The nearest trap filled first. When gas arrived, it took the top of the trap and pushed the oil out through the spill point into the middle trap. There were not enough hydrocarbons for the farthest trap, so it stayed water-bearing, although its shape may be perfect.
6
The source rock is today at a depth where the temperature is 115 °C, but there are no signs of present-day generation. What explanation is most likely?
1. A.The rock contains no organic matter
2. B.The temperature was measured incorrectly
3. C.The geothermal gradient has increased with time
4. D.In the past the rock was deeper and hotter, and after the uplift it cooled: its organic matter has already experienced a higher temperature
Show the answer
Correct answer: D. In the past the rock was deeper and hotter, and after the uplift it cooled: its organic matter has already experienced a higher temperature
Maturation cannot be reversed, and the highest temperature the rock has been through determines it. After uplift and cooling, generation dies away, even if the present temperature formally falls in the window. Vitrinite reflectance confirms this: it is higher than the present depth would give.

Updated: 26 October 2026