1

CHAPTER ONE

1.0 INTRODUCTION

Trap mechanism in hydrocarbon migration is

fundamental in the analysis of a prospect and an

important part in any successful oil and gas

exploration or resource assessment program. A trap

can be defined as any geometric arrangement of

rock, regardless of origin, that permits

significant accumulation of oil or gas, or both, in

the subsurface. Although we define a trap as the

geometric configuration that retains hydrocarbons

several critical component must be in place for a

trap to be effective, including adequate reservoir

rocks and seals, and each of these must be

addressed during trap evaluation.

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The oil and gas within a trap is part of the

petroleum system, whereas the trap itself is part

of one or more sedimentary basins and is evaluated

as part of a prospect. The hydrocarbon-forming

process and the trap-forming process occur as

independent event and commonly at different types.

The timing of the trap-forming process is important

in a petroleum system study because if the trap

forms before the hydrocarbon-forming process the

evidence (oil and gas) that a petroleum system

exist is preserved. The volume of oil and gas

preserved depends on the type and the size of the

trap, which is important in the evaluation of the

prospect. The critical component of a trap (the

reservoir, seal, and the geometric arrangement with

each other) can be combined in variety of ways by a

number of separate processes. Different authors

3

have focused on various trap attributes as the key

elements or elements of their classifications.

1.1 HYDROCARBON MIGRATION

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Hydrocarbon migration refers to the movement of

petroleum from the source rock to the reservoir

rocks. It is important to understand this process

so that the direction of migration and trapping of

petroleum can be predicted. Many different theories

have been proposed in the past but it is now clear

that petroleum is mainly transported as a separated

phase and that the process is mainly driven by the

buoyancy of petroleum relative to water. The

solubility of oil in water is very low for most

compounds. The solubility of oil in water is very

low for most compounds. The solubility of gas,

particularly methane, is much higher both in oil

and water and increases with depth (pressure).

There is however, also very limited flow in

sedimentary basins to transport petroleum.

5

Figure 1.0: petroleum geology, (migration process

in hydrocarbon migration) shanawaz mustafa

Figure 1.2: diagram illustrating the movement and

accumulation of hydrocarbon (Kevin.T Bibble)

6

1.2 PRIMARY MIGRATION

Primary migration is here defined as the

movement of hydrocarbons (oil and natural gas) from

mature organic-rich source rocks to an escape point

where the oil and gas collect as droplets or

stringers of continuous-phase liquid hydrocarbon

and secondary migration can occur. The escape point

from the source rock can be any point where

hydrocarbons can begin to migrate as continuous-

phase fluid through water-saturated porosity. The

escape point then could be anywhere the source rock

is adjacent to a reservoir rock, an open fault

plane, or an open fracture. Secondary migration is

the movement of hydrocarbons as a single

continuous-phase fluid through water-saturated

rocks, faults, or fractures and the concentration

of the fluid in trapped accumulations of oil and

7

gas. Numerous mechanisms for primary migration have

been proposed. The main proposed mechanisms for

secondary migration are buoyancy and hydrodynamics.

The mechanisms of primary hydrocarbon migration

and the timing of hydrocarbon expulsion have been

debated by petroleum geologists since the beginning

of the science. Mechanisms proposed for primary

hydrocarbon migration include: solution in water,

diffusion through water, dispersed droplets, soap

micelles, continuous-phase migration through the

water-saturated pores, and others. Early workers

generally favored early expulsion of hydrocarbons

with the water phase of compacting sediments,

primary hydrocarbon migration, and secondary

migration through reservoir carrier beds is the

necessary next step for the formation of a

commercial oil or gas accumulation. A thorough

8

understanding of the mechanics of secondary

hydrocarbon migration and entrapment is useful in

the exploration for oil and gas. Knowledge in this

area of exploration can be critical in tracing

hydrocarbon migration routes, interpreting

hydrocarbon shows, predicting vertical and lateral

seal capacity, exploiting discovered fields, and in

the general understanding of the distribution of

hydrocarbons in the subsurface.

1.3 SECONDARY MIGRATION

The hydrocarbons expelled from a source bed next

move through the wider pores of carrier beds (e.g.,

sandstones or carbonates) that are coarser-grained

and more permeable. This movement is

termed secondary migration. The distinction between

primary and secondary migration is based on pore

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size and rock type. In some cases, oil may migrate

through such permeable carrier beds until it is

trapped. If an oil droplet were expelled from a

source rock whose boundary was the seafloor, oil

would rise through seawater as a continuous-phase

droplet because oil is less dense than water and

the two fluids are immiscible. The rate of rise

would depend on the density difference (buoyancy)

between the oil and the water phase. The main

driving force then for the upward movement of oil

through sea water is buoyancy. Buoyancy is also the

main driving force for oil or gas migrating through

water-saturated rocks in the subsurface. In the

subsurface, where oil must migrate through the

pores of rock, there exists a resistant force to

the migration of hydrocarbons that was not present

in the simple example. The factors that determine

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the magnitude of this resistant force are (1) the

radius of the pore throats of the rock, and (2) the

hydrocarbon-water interfacial tension, and (3)

wettability. These factors, in combination, are

generally called "capillary pressure." Capillary

pressure has been defined as the pressure

difference between the oil phase and the water

phase across a curved oil-water interface pointed

out that capillary pressure between oil and water

in rock pores is responsible for trapping oil and

gas in the subsurface. 

11

Figure 1.2 definition of primary and secondary

migration (after tissot and welte).

1.4 DRIVING FORCES FOR HYDROCARBON MIGRATION

Under hydrostatic conditions, buoyancy is the main

driving force for continuous-phase secondary

hydrocarbon migration. When two immiscible fluids

(hydrocarbon and water) occur in a rock, a buoyant

force is created owing to the density difference

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between the hydrocarbon phase and the water phase.

The greater the density difference, the greater the

buoyant force for a given length hydrocarbon column

(always measured vertically). For a static

continuous hydrocarbon column, the buoyant force

increases vertically upward through the column.

1.5 EFFECTS OF HYDRODYNAMICS ON DRIVING FORCES

The importance of hydrodynamics with regard to

oil entrapment in structural traps has been

discussed in detail by Hubbert (1953). Numerous

other authors have since documented the effects of

hydrodynamics on structural oil reservoirs

throughout the world. In thinking of the effects of

hydrodynamics on secondary migration and primarily

stratigraphic-type entrapment of hydrocarbons, we

must consider how a hydrodynamic condition would

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effect the buoyant driving force of a hydrocarbon

filament in the subsurface. Hydrodynamic conditions

in the subsurface change the buoyant force, and

therefore the migration potential, for a

hydrocarbon column of a given height. Buoyancy, as

has been defined for a static oil filament, is the

pressure in the water phase minus the pressure in

the oil phase at a given height above the free

water level. When a hydrodynamic condition exists,

the pressure in the water phase (and therefore the

buoyant force) at any point will be different from

that for hydrostatic conditions.

1.6.0 RESISTANT FORCES TO SECONDARY MIGRATION

In a previous example we discussed how a

filament of oil released at the seafloor would rise

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through seawater because of the force of buoyancy.

If the same filament of oil or gas is required to

move through a water-saturated porous rock we have

introduced a resistant force to hydrocarbon

movement. For the hydrocarbon filament or globule

to move through a rock, work is required to squeeze

the hydrocarbon filament through the pores of the

rock. In more technical terms, the surface area of

the hydrocarbon filament must be increased to the

point that it will pass through the previously

water-saturated pore throats of the rock. The

magnitude of this resistant force in any

hydrocarbon-water-rock system then is determined by

the radius of the pore throats of the rock; the

hydrocarbon-water interfacial tension (surface

energy); and wettability as expressed by the

contact angle of hydrocarbon and water against the

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solid pore walls as measured through the water

phase. This resistant force to migration is

generally termed "capillary pressure."

For a simplified example, visualize a hydrocarbon

filament trying to move upward through a water-

saturated cylindrical pore .The variables of the

resistant force to hydrocarbon movement can be

expressed by a simple equation (Purcell, 1949):

Where Pd = hydrocarbon-water displacement pressure

(dynes/cm2);   = interfacial tension (dynes/cm);   

= wettability, expressed by the contact angle of

hydrocarbon and water against the solid (degrees);

and R = radius of largest connected pore throats

(cm). The displacement pressure is that force

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required displacing water from the cylindrical pore

and forcing the oil filament through the pore.

1.6.1 INTERFACIAL TENSION

Interfacial tension can be defined as the work

required enlarging by unit area the interface

between two immiscible fluids (e.g., oil and

water). Interfacial tension is the result of the

difference between the mutual attraction of like

molecules within each fluid and the attraction of

dissimilar molecules across the interface of the

fluids.

Oil-water interfacial tension varies as a function

of the chemical composition of the oil, amount and

type of surface-active agents, types and quantities

of gas in solution, pH of the water, temperature,

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and pressure. At atmospheric pressure and 70°F,

interfacial tension of crude oils and associated

formation water for 34 Texas oil reservoirs of

different ages ranged from 13.6 to 34.3 dynes/cm,

with a mean of 21 dynes/cm (Livingston, 1938). Oil-

water interfacial tension generally tends to

decrease with increasing API gravity and decreasing

viscosity (Livingston, 1938).

With increasing temperature, oil-water interfacial

tension generally decreases. For pure benzene-water

and decane-water systems, interfacial tension

decreases between 0.03 to 0.08 dynes/cm/°F

(Michaels and Hauser, 1950) depending on the

pressure.

In attempting to quantify oil-water-rock

displacement pressure, a value for oil-water

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interfacial tension in the subsurface must be

measured or estimated. Sophisticated laboratory

equipment can measure oil-water interfacial tension

at reservoir temperature and pressure. If this

equipment is not available, interfacial tension can

generally be measured at atmospheric conditions in

most chemical laboratories. The results of

atmospheric interfacial tension measurements must

be extrapolated to subsurface temperature and

pressure. If no laboratory data are available for

the oil-water system in question, then an estimate

must be made. Livingston's mean value for 34 Texas

crude oils of 21 dynes/cm at 70°F is the best value

for medium-density crude oils (30 to 40° API). A

value of approximately 15 dynes/cm may be

appropriate for higher gravity crude oils (greater

than 40° API) with 30 dynes/cm being a reasonable

19

approximation for low-gravity crude oils (less than

30° API). These estimates or measurements at

atmospheric temperature (70°F) must be extrapolated

to reservoir temperature. It is suggested that the

oil-water interfacial tension value at 70°F be

decreased 0.1 dynes/cm/°F temperature increase

above 70°F.

1.6.2 WETTABILITY

Wettability can be defined as the work

necessary to separate a wetting fluid from a solid.

In the subsurface we would generally consider water

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the wetting fluid and the solid would be grains of

quartz in sandstone, calcite in a limestone, etc.

The adhesive force or attraction of the wetting

fluid to the solid in any oil-water-rock system is

the result of the combined interfacial energy of

the oil-water, oil-rock, and water-rock surfaces.

Wettability is generally expressed mathematically

by the contact angle of the oil-water interface

against the rock or pore wall as measured through

the water phase. For rock-fluid systems with

contact angles between 0 and 90°, the rocks are

generally considered water-wet; for contact angles

greater than 90°, the rocks are considered oil-wet.

Water-wet rocks would imbibe water preferentially

to oil. Oil-wet rocks or oil-wet surfaces would

imbibe oil preferentially to water. Although a

contact angle of 90° has generally been considered

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the break over point to an oil-wet surface, Morrow

et al (1973) stated that a contact angle of greater

than 140° in dolomite laboratory packs was

necessary for oil to be imbibed. Water-laid

sedimentary rocks are generally considered to be

preferentially water-wet owing to the strong

attraction of water to rock surfaces and the

initial exposure of pore surfaces to water rather

than hydrocarbons during sedimentation and early

diagenesis. Water is thought by many workers to be

a perfect wetting fluid and a thin film of water

would coat all grain surfaces. If this is the

situation, the contact angle for oil-water-rock

systems would be zero. The wettability term in the

displacement pressure equation would then be unity,

as the cosine of zero is one. If water is not a

perfect wetting fluid and the oil-water contact

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angle is greater than zero, the displacement

pressure should theoretically decrease for that

oil-water rock system. L. J. M. Smits (1971,

personal commun.) has done experimental work on

identical size bead packs which suggests that

displacement pressures are only slightly affected

by changing the oil-water-solid contact angle from

0 to 85°. Similar results were obtained by Morrow

et al (1973) on displacement pressure tests in

dolomite packs with contact angles ranging from 0

to 140°. These data and the general assumption that

most rocks are preferentially water-wet suggest

that the wettability term in the displacement

pressure equation can be considered unity.

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If the rocks are partially oil-wet, then the

wettability term can be significant in reducing

displacement pressure from that for the water-wet

case. In the subsurface, rocks are seldom

completely oil-wet but are fractionally oil-wet,

that is, some of the grain surfaces are oil-wet and

some are water-wet. According to Salathiel (1972),

this would most likely occur in reservoir rocks

where oil has been trapped and the grain surfaces

in the larger pores would be exposed to the

surface-active molecules in the oil phase and form

an oil film or coating on the grain, making it

preferentially oil-wet. The pore surfaces at the

smaller pores or in the corners of the larger pores

that are not saturated with oil would remain water-

wet. Fatt and Klikoff (1959) have determined that

when a rock is partially oil-wet there is a

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reduction in the oil-water displacement pressure

for that oil-water-rock system. They suggested that

the degree of fractional wettability needed to

significantly reduce displacement pressure from

that for the water-wet case is greater than 25%

oil-wet grain surfaces.

Figure 1.3 driving forces on hydrocarbon migration

wikipedea(2009)

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CHAPTER TWO

HYDROCARBON TRAPS

2.0 HYDROCARBON TRAPS

A trap is a geologic structure or a

stratigraphic feature capable of retaining

hydrocarbons. Hydrocarbon traps that result from

changes in rock type or pinch-outs, unconformities,

26

or other sedimentary features such as reefs or

buildups are called stratigraphic traps.

Hydrocarbon traps that form in geologic structures

such as folds and faults are called structural

traps. Any mixture of structural and stratigraphic

elements is called a combination trap.

2.1 STRUCTURAL TRAPS

Structural traps are created by syn-to post

depositional deformation of strata into a geometry

(a structure) that permits the accumulation of

hydrocarbons in the subsurface. The resulting

structures involving the reservoir, and usually the

seal intervals, are dominated by either folds,

faults, piercements, or any combination of the

foregoing. Traps formed by gently dipping strata

beneath an erosional unconformity are commonly

27

excluded from the structural category, although as

sub unconformity deformation increases these

distinction becomes ambiguous. Super posed

multiple deformations may also blur the forgoing

distinctions.

Subdivisions of structural traps have been

proposed by many authors based on a variety of

schemes, example of these are fault dominated traps

and fold dominated traps.

2.1.1 FOLD DOMINATED TRAPS

Structural traps that are dominated by folds at

the reservoir-seal level exhibit a wide variety of

geometries and are formed or modified by a number

of significantly different syn-and post

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depositional deformation mechanisms. Although

usually considered to result from tectonically

induced deformation the term fold is purely

descriptive and refers to curved or non planer

arrangements of geologic (usually bedding)

surfaces. Therefore, folds include not only

tectonically induced phenomena but also primary

depositional features, gravity-induced slumping,

compaction effect etc. it is convenient to divide

prospect-scale folds into two categories those that

are directly fault related and those that are

largely fault free.

Most fault related folds result from bending

above non planar fault surface. Crystalline

basement may or may not be involved, and strata

shortening, extension, or transcurrent movements

may have occurred. Common examples are fault bend

29

folds and fault propagation folds in detached fold

and thrust belts. Fault bend folds are also common

in extensional Terranes. Other faulted related

folds include drag fold, or fold formed by frictional

forces acting across a fault, and drape folds,

those formed by flexure above a buried fault along

which there has been renewed movement. These latter

folds however are not caused by slip over a

nonplanar fault surface. Also, drape folds do not

involve significant strata shortening or extension

at the reservoir level. Fault free, or lift off folds result

from buckling caused by strata shortening above a

docollement, usually within a thick or very

efficient sequence of evaporates or shale. Kink bands

and chevron folds are special types of fault free

folds. Other type of fault free folds may form by

bending above material that moves vertically or

30

horizontally by flow without significant strata

shortening or extension at the reservoir seal

interval.

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Figure 2.1: diagram illustrating fault dominated

trap (Kevin.T Bibble)

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2.1.2 FAULT DOMINATED TRAP

As already pointed out, faults can be extremely

important to the viability of a trap by providing

either seals or leak points. They are capable of

acting as top, lateral, or base seals by

juxtaposing relatively permeable rock units against

more permeable reservoir units or by acting as

seals surfaces due to impermeable nature of the

material along the faults. In addition, they may

act as leak points by juxtaposing of permeable

units or by creation of a fracture network. The

term fault is descriptive in that it refers to a

surface across which they have been displacement

without reference to the cause of that reference

(either, whether it is tectonically,

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gravitationally, diagenetically or otherwise

induced). Structural traps that are dominated by

faults at the reservoir - the seal level (the fault

itself makes the trap by sealing the reservoir

without an ancillary fold) can be divided into

three categories based on the types of separation,

or slip if it is known that geologic surface

exhibit across the fault. These are normal,

reverse, and strike separation or slip fault trap.

2.2 NORMAL FAULT

Normal traps are the most common fault

dominated structural traps. They are of two

fundamentally different geometries and are most

common in two different tectonostratigraphic

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setting. Normal fault involving the basement occur

in areas of significant crustal extension, such as

the gulf of cuez and the North Sea, and are

characterize by tilted fault block that exhibit a

zigzag map pattern. Probably the most important

trap geometry is the trap door closure at fault

intersection. Syn-and post depositional normal

fault that are detached from the basement occur in

area of rapid subsidence and sedimentation,

commonly on passive continental margins, such as

the USA, gulf coast, Niger-Delta and are

characterized by a listric profile and a cuspate

map pattern that is usually concave basinward. On

the downthrown side of major displacement normal

fault in these setting smaller synthetic and

antithetic fault dominated trap are typically

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keystone normal fault dominated traps above deep

seated salt intrusions are also common.

2.3 REVERSE FAULT

Reverse fault traps may be associated with detached

or basement involved thrust (No angle or high angle

reverse faults.) these structures tend not to

produce pure fault dominated traps because of

attendant folding. In this position, the hanging

wall moved up relative to the foot wall, indicating

reverse fault activity. The picture shows that the

central hanging wall was pushed up relative to the

foot wall. Most of the faults in the Rocky

Mountains are reverse fault.

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Figure 2.3: types of traps in which folding

dominate the reservoir-seal interval. Fault related

traps include (A) fault bend (B) fault propogation,

37

(C) fault grab (D) fault drape. Fault free types

include (E) lift off, (F) chevron/king band, (G)

diaper, and (H) differential compaction

2.4 STRATIGRAPHIC TRAP

In 1936 levorsen proposed the term

stratigraphic features in which a variation in

stratigraphy is the chief confining element in the

reservoir which traps the oil. The existence of

such non structural trap has been recognized

atleast the late 1800. Today we would define a

stratigraphic trap as one which the requisite

geometry and reservoir- seals combination where

formed by any variation in the stratigraphy that is

independent of structural deformation except for

regional tilting.

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Many attempts have been made to classify

types of stratigraphic traps. Early efforts, while

not specifically using the term stratigraphic, lead

to broad categories of traps that where close

because of varying porosity within rocks later

works recognized that considerable variability

exist among such trap, and subdivision became more

numerous. A number of treatments of stratigraphic

traps provide information on different approaches

to classification and supply abundant, we generally

follow Ritten-House, (1972) and divide

stratigraphic traps into primary and depositional

stratigraphic trap, stratigraphic traps associated

with unconformities, and secondary stratigraphic

traps.

39

Figure 2.4: types of traps in which faulting

dominate the reservoir-seal interval. (A) Basement

involved normal fault trap and trap. (B) Synthetic

40

detached listric normal fault traps (C) two types

of reverse fault traps. (D) strike-slip traps

2.4.1 PRIMARY OR DEPOSITIONAL STRATIGRAPHIC TRAP

Primary or depositional stratigraphic traps

are created by changes in contemporaneous

deposition. As described here such traps are not

associated with significant unconformity two

general classes of primary stratigraphic traps can

be recognized: those formed by lateral depositional

changes, such as facies changes and depositional

pinchouts, and those created by buried depositional

relief.

Facies changes may juxtapose potential

reservoir rocks and impermeable seal rocks over

relatively short lateral distance in either

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siliciclastic or carbonate settings. The lateral

transition from reservoir to seal is generally

gradational, leading to possible non economic

segment within the reservoir. Particular care must

be taken to identify strike closure in this type of

trap. Deposional pinchouts may lead to reservoir

and seal combination that can trap hydrocarbon. The

transition from reservoir to lateral seal may be

abrupt, in contrast to facies change traps. Strike

closure is also a risk for pinchouts traps.

Both lateral facies change and depositional

pinchouts traps generally require a component of

regional dip to the effective. Both types are

common elements of combination structural-

stratigraphic traps, particularly if the structure

was growing during deposition of the reservoir and

seal rocks

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The general second general class of primary

stratigraphic traps is associated with buried

depositional relief. These traps are equivalent to

the constructive paleogeomorphic traps of Martin

(1966). Carbonate reefs provide a classic example

of potential traps associated with buried

depositional relief. Reef growth with time enhances

depositional relief, and the transition from tight

lagoonal rocks to porous and permeable backreef-

reef-fore reef rock may provide a good reservoir-

lateral seal combination. The relationship between

the forereef rocks and adjacent basinal deposits

(potential source rocks) can create excellent

migration partway. Formation of a top seal requires

that reef growth is terminated and that the reef is

very buried beneath the trap with low permeability

material. A key risk for this type of trap is

43

accurate prediction of porosity and permeability

with the reef complex. The Devonian reef fields of

the western Canada sedimentary basin are excellent

example of this type of trap. Another type of

buried depositional relief is associated with some

submarine fan deposit. In such depositional

settings sand- ridge depositional lobes may be

encased in shale.

44

Figure 2.5 primary or Deposional stratigraphic

traps. (A) Traps created by lateral changes in

sedimentary rock type during deposition. (B) traps

formed by buried Deposional relief.

45

2.4.2 SECONDARY STRATIGRAPHIC TRAPS

Another major category of stratigraphic traps

results from post depositional alteration of

strata. Such alteration may either create reservoir

quality rocks non reservoir or create seals from

former reservoir. Although the example used is

taken from a carbonate setting, similar digenetic

plugging can occur in just about any rock type

under the proper circumstances. Porosity occlusion

is not limited to only digenetic mineral cements.

Asphalt, permafrost, and gas hydrates are other

possible agents that may form seals for these types

of stratigraphic traps. Unfortunately it is often

difficult to predict position of the cementation

boundaries in the subsurface before drilling, and

this type of trap can be a challenging exploration

target.

46

The second type of secondary stratigraphic

traps is associated with porosity enhancement that

improves reservoir quality in otherwise tight

sections.Dolomization of limited permeability

limestones is a good example. Dissolution of

framework or material is another porosity and

permeability enhancement mechanism. Porosity

enhancement associated with dolomization and

dissolution potentially can create traps on its

own. Commonly, though, porosity enhancement is

associated with other types of traps as a modifying

element.

47

Figure 2.6: secondary digenetic stratigraphic

traps. (A) Traps created by post depositional up

dip porosity occlusion. (B) Traps created by post

depositional porosity and permeability enhancement

2.5 COMBINATION TRAP

Many of world’s hydrocarbon traps are not

simple features but instead combine both structural

and stratigraphic elements. Levorsen recognized

this in his 1967 classification of trap he noted

48

that every a complete gradation exist between

structural and stratigraphic end members and that

discovered traps illustrates almost imaginable

combination of structure and stratigraphy. Levorsen

restricted the use of the term combination trap to

features in which neither the structural nor the

stratigraphic element alone forms the traps but

both are essential to it. Many people now use the

term combination trap in a less rigorous way and

apply it to any trap that has both structural and

stratigraphic element, regardless of whether both

are required for the trap to be viable strict

adherence to the definitions does not necessarily

find hydrocarbon, both early recognition of

stratigraphic complication associated with

structural traps or structural modification of

dominantly stratigraphic trap can help eliminate

49

exploration or development suprises. An explanation

that is commonly proposed for these observations is

that reservoir conditions are hydrodynamic rather

than hydrostatic. In general, dips of oil water

contacts seldom exceed a few degrees, but higher

dips have been reported up to 10 degrees, if the

dip(tilt) of the oil water contact exceeds the trap

flanks, the trap will be flushed (generally, if

trap flank dips exceed 5 degrees, there is little

risk of flushing). Therefore, in the evaluation of

structural traps with relationship gently dipping

flanks, consideration should be given to

hydrodynamic conditions, it is important to note

that tilted oil water contacts may be related to

phenomena other than hydrodynamics (e.g), variation

in reservoir characteristics and geotectonic), and

50

that present day hydrodynamic condition may not

reflect those in the past.

It is possible to calculate the theoretical

change in trap capacity and therefore the risk

associated with trap capacity and therefore the

risk associated with trap flushing in a strongly

hydrodynamic situation. Hubbert (1953) showed that

the tilt of the oil water contact is the direction

of flow is a function of the hydraulic gradient and

the densities of both hydrocarbons and water .the

lower the oil density and greater the water flow,

the more easily the oil density and greater the

water flow, the more easily the oil is displaced.

51

Figure 2.7: combination traps. (A) Intersection of

a fault with an updip depositional edge of porous

and permeable section (B) folding of an updip

depositional pinchouts of reservoir section.

2.6 HYDRODYNAMIC TRAPS

52

Explorationists have known since about mid-

century that oil-water contacts in many

hydrocarbons-bearing traps are tilted. In other

cases, traps that have no static closure contain

hydrocarbons, and traps that do not have static

closure and should reasonably contain hydrocarbons

do not. An explanation that is commonly proposed

for these observations is that reservoir conditions

are hydrodynamic rather than hydrostatic. In

general, dips of oil-water contacts seldom exceed a

few degrees, but higher dips have been reported. If

the dip (tilt) of the oil water contact exceeds the

dip of the trap flanks, the trap will be flushed

(generally, if trap flank dips exceeds 50 , there is

little risk of flushing). Therefore, in the

evaluation of structural traps with relatively

gently dipping flanks, considering should be given

53

to hydrodynamic conditions. It is important to note

that tilted oil water contact may be related to

phenomena other than hydrodynamics (e.g.,

variations in reservoir characteristics and

neotectonics), and that present day hydrodynamic

conditions may not reflect those in the past. It is

possible to calculate the theoretical change in

trap capacity and therefore the risk associated

with trap flushing in a strongly hydrodynamic

situation. Hubbert (1953) showed that the tilt of

the oil water contact in the direction of flow is a

function of the hydraulic gradient and the

densities of both hydrocarbons and water. The lower

the oil density and greater the water flow, the

more easily the oil is displaced.

54

Figure 2.8: (A) Generalized hydrostatic trap. (B)

Generalized hydrodynamic trap. (C) Hydrodynamic

traps with increased water flow or oil density. (D)

Hydrodynamic trap without static closure created by

down dip water flow. (E) Same situation as in (D)

but with updip water flow. (F) Tilted oil-water

contact in fold dominated trap with down dip water

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movement. (G)Tilted oil-water contact in fold

dominated trap with updip water movement.

CHAPTER THREE

COMPONENT OF A TRAP

3.0 TWO CRITICAL COMPONENTS OF TRAP

To be a viable trap, a subsurface feature

must be capable of receiving hydrocarbons and

storing them for some significant length of time.

This requires two fundamental components: a

reservoir rock in which to store the hydrocarbons,

and seal (or set of seals) to keep the hydrocarbon

from migrating out of the trap. We do not consider

the presence of hydrocarbons to be critical

component of a trap, although this is certainly a

requirement for economic success. The absence of

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hydrocarbons may be the result of failure of other

play or prospect parameters, such as the lack of a

pod of active source rock or migration conduits,

and it may have nothing to do with the ability of

an individual feature to act as a trap.

3.1 RESERVIOR

The reservoir within a trap provides the

storage space for the hydrocarbons. This requires

adequate porosity within the reservoir interval).

The porosity can be primary (depositional),

secondary (digenetic), or fractures, but it must

supply enough volume to accommodate a significant

amount of fluids. The reservoir must also be

capable of transmitting and exchanging fluids. This

requires sufficient effective permeability within

the reservoir interval and also along the migration

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conduit that connects the reservoir with a pod of

active source rock. Because most traps are

initially water filled, the reservoir rock must be

capable exchanging fluids as the original formation

water is displaced by hydrocarbons, traps are not

passive receivers of fluids into otherwise empty

space; they are focal points of active fluid

exchange.

A trap that contains only one homogenous

reservoir rock is rare. Individual reservoir

commonly include lateral/or vertical variation in

porosity and permeability. Such variation can be

caused either by primary depositional processes or

by secondary digenetic or deformational effects and

can lead to hydrocarbon saturation but non

productive waste zones within a trap. Variation in

porosity and, more importantly, permeability can

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also create transition that occurs over some

distance between the reservoir and the major seals

of a trap. This interval may contain significant

amount of hydrocarbons that are difficult to

produce effectively. Such intervals should be

viewed as uneconomic parts of the reservoir and not

part of the seal. Otherwise, trap spill points may

be mis-identified. Many traps contain several

discrete reservoir rocks with interbedded

impermeable units that form internal seals and

segment hydrocarbon accumulations into separate

compartments with separate gas-oil-water contacts

and different pressure distributions.

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Figure 3.0: common trap limitations. (A) Waste or

non productive zones in trap. (B) Multiple

impermeable layers in trap creating several

individual oil-water contacts (C) Non-to poorly

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productive transition zone. (D) Lateral transition

from reservoir to seal. (E) Lateral

stratigraphically controlled leak point. (F)

lateral leak point or thief bed.

3.2 SEAL

The seal is equally critical component of a

trap, without effective seals, hydrocarbons will

migrate out of the reservoir rock with time and the

trap will lack viability. Most effective seals for

hydrocarbon accumulations are formed by relatively

thick; laterally continuous, ductile rocks with

high capillary entry pressure, but other types of

seals may be important parts of individual traps

(e.g. Fault zone material, volcanic rock, asphalt,

and permafrost). All traps require some form of top

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seal when the base of the top seal is convex upward

in three dimensions, the contours drawn to

represent this surface (called the sealing surface

by Downey, 1984) close to map view. If these are

the case, no other seal is necessary to form an

adequate trap. In fact some authors have used the

basic convex or non convex geometry of sealing

surface as a way of classifying traps.

Many traps are more complicated and require

that, in addition to a top seal, other effective

seals must be present. Lateral seals impede

hydrocarbon movement from the sides of a trap and

are a common element of successful stratigraphic

traps. Facie changes from porous and permeable

rocks to rocks with higher capillary entry

pressures can form lateral seals, as can lateral

digenetic changes from reservoir to tight rocks.

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Other lateral seals are created by the

juxtaposition of dissimilar rock types across

erosional or depositional boundaries. Traps in

incised valley complexes commonly rely on this type

of lateral seal. Stratigraphic variability in

lateral seals poses a risk of leakage and trap

limitation. Even thinly interbedded intervals of

porous and permeable rock (thief beds) in a

potential lateral seal can destroy an otherwise

viable trap. Base seals are present in many traps

and most commonly stratigraphic in nature. The

presence or absence of an adequate base seal is not

a general trap requirement, but it can play an

important role in deciding how a field will be

developed.

Faults can be important in providing seals

for trap, and fault leak is a common trap

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limitation. Fault can create or modify seals by

juxtaposing dissimilar rock types across the fault,

by smearing or dragging less permeable material

into the fault zone, by performing a less permeable

gouge because of differential sorting and

cataclasis, or by preferential digenesis along the

fault, fault induced leakage may result from

juxtaposing of porous and permeable rocks across

the fault or by formation of a fracture network

along the fault itself.

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Figure 3.1: diagram illustrating positions of seal

in a hydrocarbon system.

CHAPTER FOUR

POROSITY AND PERMEABILTY

4.0 INTRODUCTION TO POROSITY AND PERMEABILITY

Hydrocarbon accumulations can occur only if

all essential elements (source rock, reservoir

rock, seal rock, and overburden rock) and processes

(generation-migration-accumulation of petroleum and

trap formation) have operated adequately and in the

proper timespace framework. Absence or inadequacy

of even one of the elements or processes eliminates

any chance of economic success. Thus, sandstone

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reservoir parameters (reservoir size, porosity, and

permeability) are among the geologic controls that

have to be included in the consideration of risk

factors for plays and prospects. The importance of

accurate pre-drill assessments, including reservoir

quality, is growing as oil and natural gas

companies are increasingly exploring deeper

targets. The proportion of undeveloped, deep

reservoirs was even higher for gas fields. The

trend toward greater producing depths has not been

limited to the North Sea. Anomalously high

porosities and permeabilities in deeply buried

sandstones can extend the economic basement and

provide critical support for commercial production.

Four known major causes of anomalously high

porosity in sandstones are as follows: (1) grain

coats and grain rims (effective only in detrital-

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quartz–rich sandstones), (2) early emplacement of

hydrocarbons, (3) shallow development of fluid

overpressure, and (4) secondary porosity. Although

these phenomena are generally known to geologists,

misconceptions exist regarding their occurrence and

effectiveness. In this article, we discuss

quantification and predictability of anomalous

porosity as the result of the first three causes.

4.1 POROSITY

Porosity refers to the percentage of total

volume of a material that is occupied by voids or

air spaces that exist between the rock grains. The

more porous a material is, the greater the amount

of open space, or voids, it contains. Stored in

these voids are liquids and gases. Porosity differs

from one material to another. Unconsolidated

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deposits of clay have the greatest porosities

because of their crystallographic structure; they

are comprised of parallel sheets of clay minerals.

Unconsolidated deposits of sand have lower

porosities because of the nature of the sand grains

to each other. Source rocks have high porosities;

the best source materials are clays & shales, but

these same materials make poor reservoir rocks.

Porosity of a rock is a measure of its ability to

hold a fluid.   Mathematically, porosity is the

open space in a rock divided by the total rock

volume (solid +  space or holes).  Porosity is

normally expressed as a pecentage of the total rock

which is taken up by pore space.  For example, a

sandstone may have 8% porosity.  This means 92

percent is solid rock and 8 percent is open space

containing oil, gas, or water.  Eight percent is

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about the minimum porosity that is required to make

a decent oil well, though many poorer (and often

non-economic) wells are completed with less

porosity. Even though sandstone is hard, and

appears very solid, it is really very much like a

sponge (a very hard, incompressible sponge). 

Between the grains of sand, enough space exists to

trap fluids like oil or natural gas!  The holes in

sandstone are called porosity (from the word

“porous”). Here is a very thin slice (thinner than

a human hair) of actual sandstone as seen through a

microscope.  The larger brown and yellow pieces are

grains of “quartz,” an extremely common mineral. 

Between the grains, you can see the porosity in the

rock.If you take a piece of sandstone and pour

water on it, you will see the water is absorbed

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right into the rock.  The water is soaked into the

porosity.

The porosity is shown as black in the drawing on

the right.  Oil or gas will fill these holes in the

rock. Notice that the more spherical the grains

are, the more space or porosity is left between

them.  Hence, well-rounded sandstone will have more

porosity than a poorly-routed one!  A geologist

loves to encounter well-rounded sandstone, because

they hold the most oil and gas of any of the

clastic rocks.

4.2 PERMEABILITY

Permeability (measured in centimeters per

second) refers to the ability of a material to

transmit [fluid or gas]. The rate at which a

material will transmit a fluid or gas depends upon

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total porosity, number of interconnections between

voids, and size of interconnections between voids.

For example, although clay has a higher porosity

than sand (clay has a greater number of voids), the

voids that make up the clay are not interconnected

and therefore cannot transmit the fluid or gas out

of it. The permeability of a typical clay in

Louisiana would be 1 x 10-7 cm/sec, or a movement of

about 3 feet in 30 years. Therefore movement of a

fluid or gas out of clay is very difficult. Sand on

the other hand has a typical permeability of 1 x

10-5 cm/sec, or a movement of about 300 feet in 30

years. Therefore sand has greater permeability than

clay. The permeability of a rock is a measure of

the resistance to the flow of a fluid through a

rock.  If it takes a lot of pressure to squeeze

fluid through a rock, that rock has “low

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permeability” or “low perm.”  If fluid passes

through the rock easily, it has “high

permeability,” or “high perm.”

Table 1.0: diagram illustrating permeability chart

for typical sediments.

Permeability in petroleum-producing rocks is

usually expressed in units called millidarcys (one

millidarcy is 1/1000 of a darcy).  Most oil and gas

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reservoirs produce from rocks that have ten to

several hundred millidarcys.  One darcy (1000

millidarcys) is a huge amount of permeability!

In the last 10 years, an increasing amount of US

gas production is coming from shale gas wells. 

Shale has a lot of porosity (much more than

sandstone), but extremely low permeability.  That

means shale has historically been a poor producer

of hydrocarbons. While gas has been produced from

shales for over a hundred years, quantities were

small.  Two things have changed the situation,

allowing for increased shale gas development. 

These concepts have allowed petroleum companies to

artificially induce more permeability into shale

gas rocks:

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CHAPTER FIVE

SUMMARY AND CONCLUSION

We have defined a trap as any geometric

arrangement of rock that permits significant

accumulation of hydrocarbons in the subsurface. We

do not consider the presence of hydrocarbons in

economic accounts to be a critical element of a

trap. The absence of oil or gas in a subsurface

74

feature can be the result of failure or absence of

other essential elements or processes of a

petroleum system and may have nothing to do with

the viability of a trap. Although we use the

geometric arrangement of key elements to define a

trap, trap evaluation must include much more than

just mapping the configuration of those elements.

Reservoir and seal characteristics are so important

to trap viability that their evaluation must be an

integral part of any trap study. Traps can be

classified as structural, stratigraphic, or

combination trap, in addition, hydrodynamic flow

can modify traps and perhaps lead to hydrocarbon

accumulations where no conventional traps exist, as

more and more of the world’s hydrocarbon provinces

reach mature stages of exploration, such traps may

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provide some of the best opportunities for future

discoveries.