Subtopic: Basic Concepts of Petroleum Geology

Requirements for Petroleum Accumulation

The task of finding a petroleum field is not a simple one. First, there must be a rock containing
original organic matter--a source rock . Usually this is a mud rock or shale, which is a very common
rock type and makes up about 80% of the world's sedimentary rock volume. However, even an
average shale contains only about 1% to 2% organic matter, and this number can vary widely. Many
shales have very low organic content and make poor source rocks.
Then, the source rock must be buried deeply so that temperature and time can cause the organic
matter to mature into petroleum. This usually requires deposition into sedimentary basins,
depressed areas thickly filled by sediments. Our search for petroleum is further limited, since over
half of the world's continental areas and adjacent marine shelves have sediment covers either too
thin or absent.
Even where the organic matter can become mature, not all of it becomes petroleum. In a typical
example ( Figure 1 ) a normal marine shale with only 1% original organic matter will have less than
a third of it converted to the hydrocarbon molecules that make up oil and natural gas (Waples,
1981). The rest remains behind as an insoluble organic residue.
Figure 1
However, the least efficient step is yet to come. Of all the petroleum generated, only a small part,
usually less than 1% (Hunt, 1977), is able to undergo migration out of the source bed to accumulate
within a porous and permeable reservoir. The majority of petroleum, or even in some cases all of it,
will be dispersed for lack of a good arrangement of strata to trap it, or will leak out to the surface,
for lack of a good impermeable seal or caprock.
Five factors, therefore, are the critical risks to petroleum accumulation ( Figure 2 ): (1) a mature
source rock, (2) a migration path connecting source rock to reservoir rock, (3) a reservoir rock that
is both porous and permeable, (4) a trap, and (5) an impermeable seal.
Figure 2
If any one of these factors is missing or inadequate, the prospect will be dry and the exploration
effort will be unrewarded. Not surprisingly then, less than half of the world's explored sedimentary
basins have proved productive, (Huff, 1980) and typically only a fraction of 1% of the petroleum
basin's area, and at most 5% to 10%, is actually prospective (Weeks, 1975).
 Technical and Economic Risks in Exploration

There are a number of technical and economic risks involved in the

exploration effort, such as the ability to recover the petroleum and the
quality of the oil or gas. Less than 60%, and sometimes as low as 10% of
the oil in the ground (oil-in-place) and 70% to 90% of the gas-in-place has
proved economically recoverable by modern technology. The geological
setting must be accurately assessed to optimize this recovery.
Furthermore, in any petroleum basin, there will be some traps that are
too small or reservoirs of too poor quality to pay back drilling and
production costs. Assessors also need to be able to predict whether the
product will be oil or gas, since in remote areas the added difficulties and
handling costs of natural gas may be prohibitive. Similarly, it is often
important to predict the chemistry of crude oils and natural gas mixtures,
particularly in areas where the results may be only marginally
commercial. These must all be, in part, considerations of the exploration
geologist.
At this point, the task may seem overwhelmingly difficult, but it is
important to remember that Nature follows rules and does not randomly
distribute this petroleum beneath the earth's surface. Our understanding
of these rules is based on numerous past lessons learned from the drilling
of many successful wells and many dry holes. It is the application of these
rules, to situations that are always somewhat unique, that is the "art"
within the science of petroleum geology.
 Subtopic: Petroleum G
Petroleum Chemistry eneration and Maturation
The topic of organic chemistry is very complex, even though our concerns are only with the simplest organic
compound group, the hydrocarbons. This is the group that makes up most of petroleum. Strictly speaking,
hydrocarbons are compounds that contain only two elements, hydrogen and carbon. Consequently, petroleum is quite
simple in its elemental composition. It contains relatively few impurities, mainly atoms of nitrogen, sulfur, and oxygen.
Table 1 (below), shows the average composition of petroleum in all three of its natural states of matter, as natural gas,
liquid crude oil and solid or semi-solid asphalt.
  Average Comparison of Crude oil, Natural gas, Asphalt
  Element Crude Oil Asphalt Natural Gas
(% Weight) (% Weight) (% Weight)
Carbon  82.2-87.1 80-85 65-80
Hydrogen 11.7-14.7 8.5-11 1-25
Sulfur 0.1-5.5 2-8 trace-0.2
Nitrogen 0.1-1.5 0-2 1-15
Oxygen   0.1-4.5 ------ ------
Table 1: Average chemical compositions of natural gas, crude oil, and asphalt (from Levorsen 1979) Sulfur and nitrogen
are both undesirable elements within petroleum. Sulfur is most abundant in the heavier crude oils and in asphalt. It
can also occur in natural gas mixtures such as the poisonous corrosive gas H2S. Such natural gas is called sour gas (as
opposed to sweet gas, where H2S is low or absent) . Nitrogen content is generally higher in both asphalts and natural
gas, when compared to crudes. In asphalt, it occurs mostly in high molecular weight hydrocarbon compounds called
NSO compounds because they contain impurities of nitrogen, sulfur and oxygen. In natural gas mixtures nitrogen
occurs mostly as the inactive gas N2 which lowers the heating capacity (Btu) of the natural gas. Other compounds may
also occur in natural gas mixtures, including CO2 and the inert gases.
Although the elemental composition of hydrocarbons is relatively simple, there are a vast number of ways in which the
atoms can be arranged. Compounds with similar physical and chemical properties be grouped into hydrocarbon series,
of which four are particularly important in petroleum chemistry — theparaffins, naphthenes, aromatics, and resins and
asphaltenes ( Figure 1 ).
Figure 1
Paraffins occur as chain-like structures with the general formula CnH2n+2 The carbon number, "n", ranges from one in
the hydrocarbon gas methane (CH4), the simplest member of the paraffin series, to over 40. A natural gas composed of
nearly pure methane is called dry gas. Other lightweight paraffins, with carbon numbers up to 5, are also gaseous at
normal temperatures and pressures. A natural gas that contains these other heavier paraffin gases along with methane
is called wet gas. Paraffins with carbon numbers higher than S are normally liquid. High molecular weight paraffins
become viscous, waxy solids.
Naphthenes form as closed ring structures with the basic formula CnH2n Compounds of the naphthene series have
chemical and physical properties similar to equivalent paraffins with the same carbon number. Together with the
paraffins, naphthenes form the major components of most crude oils.
The aromatics are the third group and have a structure based on a hexagonal ring of carbons, with alternate simple
and double bonds. This basic unit is called the benzene ring, after the simplest and most abundant aromatic
compound, benzene. Other aromatic compounds are made by substituting paraffinic chains or naphthenic rings at
some of the hydrogen sites, or by fusing several benzene rings together.
The fourth group, the resins and asphaltenes, are also composed of fused benzene-ring networks, but they contain
other atoms and are not true hydrocarbons. These "impurities" are the high molecular weight NSO compounds. Resins
and asphaltenes are the heaviest components of crude oil and the major components in many natural tars and
asphalts.
 Crude Oil Classifications
Crude oils may be classified by their relative enrichment in the four primary hydrocarbon groups. One method, proposed by Tissot and Welte (1978) plots
paraffins, naphthenes and the combination of aromatic and NSO compounds as three axes of a triangular graph and divides the graph into fields that represent
six crude oil classes ( Figure 1 ).
Figure 1
Most normal crude oils fall within only three of these fields. They can be either: (1) rich in paraffins (paraffinic oil); (2) they can have nearly equal amounts of
paraffins and naphthenes which together make up more than 50% of the crude (paraffinic-naphthenic oil); or (3) they can have subequal amounts of paraffins
and naphthenes, which total less than 50%, and the composition is dominated by the aromatics, resins and asphaltenes (aromatic intermediate oil).
Oil may degrade into heavy oil and tar as a result of bacterial action and of flushing by fresh meteoric waters of surface origin. This oil falls into one of two
classes (aromatic-asphaltic or aromatic-naphthenic), both of which are enriched in aromatics. Some may contain naphthenes (aromatic-naphthenic oil) but the
paraffin content is always very low. Deep burial, however, usually has the opposite effect in altering crude oil. It tends to make an oil less dense and more
paraffinic, through processes involving both thermal maturation and the precipitation and removal of asphaltic molecules.
The chemistry of petroleum determines the types and amounts of refined hydrocarbons produced. Figure 2 shows a generalized correlation between the
hydrocarbon components of petroleum, its density, and the commercial products resulting from the refining process.
Figure 2
There are several measures of the weight or density of crude oil commonly used, two of which, relative density and API degrees, are shown in Figure 2 . Natural
gas and lightweight oil yield mostly fuels. Gasoline consists mostly of medium weight hydrocarbons with carbon numbers ranging from 7 to 12. These can occur
either naturally or be cracked from higher weight molecules. Cracking is the process in which carbon-to-carbon bonds are broken down by heat, into simpler,
lighter weight hydrocarbons. Other high weight compounds, with carbon numbers greater than 15, are refined as lubricants, waxes and asphalts.
 Kerogen Types
Maturation is the complex process through which biological molecules, created by living organisms, are converted into petroleum. In the early stages of this alteration, or
diagenesis, an intermediate form of organic matter, called kerogen, is formed. Kerogen is created by the breakdown of complex biological molecules, reactions between some
of the newly created simpler molecules, and the loss of most non-hydrogen and carbon atoms like NH3, CO2 and H20.
Microscopically, kerogen can be seen as yellow-orange to brown-black particles or amorphous material. Since this material originated from different kinds of living organisms,
with different kinds and proportions of biological molecules, kerogens will not all have the same chemical compositions and will yield different types and amounts of
petroleum. Geologists have found it convenient to group kerogens into four fundamentally different classes ( Figure 1 ).
Figure 1

Type I kerogen is derived mostly from the remains of algae, and when it matures it yields mainly crude oil. It is also capable of generating the most petroleum of all the
kerogen types. Type II kerogen consists mostly of amorphous material, derived from the bacterial and mechanical breakdown of a mixture of marine, one-celled plants and
animals. This kerogen is also oil-prone but yields more natural gas than Type I. Type III kerogen, derived from the higher land plants, is sometimes known as coaly kerogen.
The humic material in Type III kerogen has a low capacity to form oil and yields mostly natural gas. Type IV kerogen consists mostly of inert particles that have been highly
oxidized before burial, like charcoal. It is the rarest kerogen type and has practically no ability to generate either oil or gas.
The chemistry of crude oil can also be linked to kerogen type and original organic matter. Usually land-derived, non-marine organic matter deposited near continental
drainage areas (Type III coaly kerogen) will form mostly gas, but any oil formed will be low sulfur, paraffinic to paraffinic-naphthenic crude oils. Marine organic matter,
particularly protein-rich types derived from marine animals (Type II mixed marine kerogen) tends to yield high sulfur aromatic-intermediate crude.
 Temperature and Time

Petroleum is generated when kerogen is subjected to the increased temperatures that accompany sediment burial ( Figure 1 ).
The alteration of kerogen to petroleum is similar to other thermal cracking reactions. Large kerogen molecules decompose upon heating, to yield smaller molecules of
petroleum These reactions usually require temperatures greater than 60 °C. At lower temperatures, during early diagenesis, natural gas, (called biogenic methane or
marsh gas) is generated through the action of microorganisms that live near the earth's surface. Vast quantities of biogenic methane are probably generated, but most of
this will not encounter a trap and will be lost to the atmosphere.
The temperature range between about 60°C and 175°C is commonly called the oil window ( Figure 1 ). This is the principle zone of oil formation. It begins at burial depths
of 1 to 2 km and ends at depths of 3 to 4 km in most areas, depending on factors such as the geothermal gradient. The first oil generated is heavy and tends to be richest
in aromatic and NSO compounds. As burial and temperature increases, the oil becomes lighter and more paraffinic. At temperatures much above 175°C, the generation
of liquid petroleum ceases and gas formation becomes dominant. When formation temperatures exceed 225°C, most kerogen has used up its petroleum-generating
capacity. Source rocks become overmature. However, some methane can still be created, even at these very high temperatures, by the breakdown of the larger, heavier
molecules of previously generated crude oil.
Since the conversion of kerogen to petroleum is basically a series of chemical reactions, time must also play a major role in this process. Young, Tertiary-age rocks must
be deeply buried or have high geothermal gradients in order to generate significant amounts of petroleum. Although generation, migration and entrapment have been
documented in rocks as young as 1.0 to 1.5 million years old, major petroleum accumulations have not been found in rocks less than 10 million years old (Halbouty et al.,
1970). On the other hand, some older Paleozoic and Mesozoic source rocks may not have been buried very deeply, perhaps only to the uppermost part of the "oil
window", but have still generated petroleum because of the time factor. However, in most petroleum occurrences, temperature appears to be a more significant factor
than time.
 Geothermal Gradients and Thermal Conductivity
Temperature, modified by time, has been instrumental in the formation of most major
petroleum accumulations. During drilling, formation temperature can be measured by
lowering self-recording thermometers into the borehole. When this is done for various
depth levels, the geothermal gradient can be determined.
The worldwide average geothermal gradient, which measures the increase in the earth's
temperature with depth, is about 26 °C/km (14°F/1000 ft). Gradients measured in
sedimentary basins around the world typically range from lows of about 18 °C/km to highs
of 55 °C/km.
A low geothermal gradient causes the first formation of oil to begin at fairly deep
subsurface levels, but it also causes the oil window to be quite broad ( Figure 1 ).

In contrast, a high geothermal gradient enhances the early formation of oil at relatively
shallow burial depths, but it causes the depth range of the oil window to be quite narrow.
Overall, however, the oil-forming process is more efficient in young source rocks, where
there is a high geothermal gradient and oil can form early at shallow depths (Klemme,
1975).
The magnitude of a petroleum basin's geothermal gradient is most often directly related
to the earth's heat flow; it will be high where heat flow is high ( Heat Flow = Geothermal
Gradient Thermal Conductivity ). Consequently, high geothermal gradients are often
found in basins that are associated with active deformation, sea floor spreading and
mountain-building (tectonic) processes. Gradients will usually be low in basins associated
with old, stable interiors of the continents, the craton. Gradients will also tend to be low
in areas insulated by cool underlying rocks or thick, rapidly deposited sediments.
Locally, the geothermal gradient will be influenced by the subsurface rocks through which
the earth's heat must pass. The thermal conductivity of rocks, is inversely related to the
geothermal gradient ( Heat Flow = Geothermal Gradient Thermal Conductivity ). It varies
both with the rock type or lithology, and the kinds and amounts of pore-filling fluids. Thus,
the geothermal gradient will normally vary vertically through a stratigraphic sequence
( Figure 2 ), and temperature will have a nonlinear relationship to burial depth.

The present-day geothermal gradient may be of less importance to maturation than

paleogeothermal conditions, particularly in areas that have undergone large-scale uplift
and erosion. The chemical reactions completed at higher temperatures are normally not
reversible. It is therefore most important to be able to establish the highest temperature
attained at some time in the geological past. Various measurement methods, or
paleothermometers, have been devised to determine the maximum formation
temperature of a source rock.
 Subsurface Pressure
Pressure, which like temperature increases with depth, plays a relatively minor role in the petroleum-generation process (Phillippi, 1965), but has other important effects.
The total overburden pressure exerted at any point in the subsurface is the sum of two forces: the weight due to the over-lying rock (lithostatic pressure) and pressure due to
fluids contained within the pore spaces (fluid or pore pressure); therefore, Overburden Pressure = Lithostatic Pressure + Fluid Pressure.. Lithostatic pressure is transmitted via
grain-to-grain contacts and averages about .6 psi/ft (.136 kg/cm2. m) (13.6 kPa/m). Fluid pressure is usually transmitted via pore-to-pore communication extending to the
surface and is then called hydrostatic pressure. For a typical subsurface brine, hydrostatic pressure gradient is about .465 psi/ft (.1052 kg/cm 2m) (10.52 kPa/m).
Pressures increase with burial depth and in a normally pressured well, the fluid pressure is always slightly less, and the lithostatic pressure slightly more, than half of the total
overburden pressure, at any depth ( Figure 1 ).
Figure 1
However, abnormally pressured rocks are sometimes encountered in drilling, often unexpectedly. This may cause serious problems. If the rocks are overpressured (i.e. where
a permeability barrier seals pore fluids off from communication with the surface), the pressure exerted by the drilling mud may not be great enough to hold back the fluids in
the rock. This could cause a well to "blow out". Underpressured rocks are less common. However, they too can cause problems, when high-pressure drilling muds enter the
lower-pressured formation causing loss of circulation and plugging up of pore spaces. This can lower the mud column in the well to such a degree that even a normally
pressured formation may blow out.
Although abnormally high pressures may be encountered in various sedimentary provinces, they are particularly prevalent in rocks deposited in delta environments where
sedimentation may be too rapid for deep shales to thoroughly compact and dehydrate. In this case, some of the weight of the overlying sediment, which would otherwise be
taken up by grain-to-grain contacts in normally compacted rocks is taken up by the fluid in the pore spaces.
 The Source Rock

Source rocks are any rocks in which sufficient organic matter to form petroleum has been accumulated, preserved, and thermally matured. Organic
particles are usually fine-grained, and will settle out most easily in quiet-water environments. Therefore, source rocks are most commonly fine-grained
rocks, particularly shales. Other potential sources are fine-grained carbonates (lime mud), mud-carbonate mixtures (marl), or coal ( Figure 1 ).
Figure 1

One of the most important factors in determining whether an organic-rich rock will become a source rock is its thermal maturity. However, some
potential source rocks have never reached this thermal level. An example is oil shales like the Green River Shale of the U.S. Rocky Mountain region,
where instant maturation can be artificially induced by heating the rocks to temperatures of about 500 ºC, a process called pyrolysis.
Tar sands, like the Athabasca tar sands of western Canada, have sometimes been regarded as immature source rocks. However, the majority opinion is
that they were once conventional oil reservoirs, in which the oil became degraded from flushing by fresh meteoric waters and by bacterial action,
these processes having converted lighter oil into a viscous asphaltic tar.
Preservation of organic matter is usually harder to achieve than its production. On land, with the exception of some lakes and coal swamps, most
organic accumulations are rapidly destroyed through oxidation and biological activity. More commonly organic matter is preserved in marine
environments.
Rapid deposition is one way to avoid the destruction of organic matter and is characteristic of source rocks in thick, prograding sediment wedges, such
as deltas. Rapid deposition, however, leads to dilution of the organic matter by sediment. Some shale source rocks found in rapidly prograding deltas
have organic contents of only 1%. Shale usually requires a higher organic content than this to be an adequate source rock. However, deltas often have
excellent source/reservoir rock geometries, and structures are developed early in response to the sediment load. In such cases, migration and
accumulation of petroleum is probably more efficient than usual, and even organic-poor shales make adequate source rocks.
In most cases, however, marine shales with organic contents high enough to be petroleum source rocks are slowly deposited, under oxygen-free
conditions that prevent organic destruction. This occurs most commonly in restricted marine environments, where a basin is silled or otherwise
prevented from easy communication with the open ocean.
 Subtopic: Migration and Accumulation Processes
Migration Processes
At present, migration is the most poorly understood and least measurable stage in
the cycle of generation, migration, and accumulation. Primary migration, which
involves the expulsion of petroleum from the source rocks, is still a great mystery.
Various models for primary migration have been proposed, although none appears
to have all the answers.
Secondary migration processes which involve the movement of petroleum through
permeable layers (carrier beds) to the trap, are better understood. Nonetheless, it
is still often very difficult to apply these concepts to the exploration of a particular
area. Although secondary migration is governed primarily by buoyancy, which
tends to move petroleum upward by displacing heavier water, the tectonic and
hydrodynamic regime also becomes important. Consequently, a wide variety of
spatial arrangements between source rocks and carrier/reservoir beds is possible
( Figure 1 ).

Figure 1
In older, more consolidated basins where there is little disruptive deformation,
secondary migration occurs updip along extensive structural-stratigraphic ramps,
that carry petroleum from the deep basin to the hinge areas or a regional arch
( Figure 2 ).

Figure 2
Long-distance migrations are possible in these cases, and large accumulations may
result if the drainage area is particularly large. However, secondary migration in
young basins that are less consolidated ( and may be overpressured ) involves
more movement through fractures and faults ( Figure 3 ).

Figure 3
In these situations, secondary migration often occurs over short distances. It is
often influenced by water released through compaction and by greater-than-
normal vertical water and petroleum movements, and the pathways are more
difficult to predict. Migration is further complicated in that it can occur quickly,
over a short time interval, or intermittently over a long time span, either early or
late in a basin's history. Thus, while the concept of secondary migration is simple
to understand, applying it to the exploration task is often exceedingly difficult.
 Reservoir Porosity and Permeability
There are two fundamental physical properties that a good reservoir must have: (1)
porosity, or sufficient void space to contain significant petroleum; and, (2)
permeability, the ability of petroleum to flow through these voids.
The only common rock types that normally have the favorable combination of
porosity and permeability to be reservoirs are sandstones and carbonates ( Figure 1 ).
Figure 1
Many porous rocks are useless as reservoirs, because their passageways or pore-
throats are too small to allow petroleum to move through them. This can be due to
fine grain size ( as in siltstones and shale ), or to poor sorting ( where fine and coarse
grain sizes are intermixed and the finer particles clog the passageways ) ( Figure 2 ,
and Figure 3 ).
Figure 2
The best reservoirs are coarse- to medium-grained and show a high degree of sorting.
Figure 3
Muddy sandstone lithologies, deposited by turbidity currents, or rocks containing
unstable minerals which are easily weathered to clay generally make poor reservoir
rocks. However, even poor reservoir qualities can be amply compensated when there
is a considerable thickness, or net pay thickness, to the oil column or great areal
extent for the productive horizon. Permeability is measured in a unit called the Darcy.
Most reservoirs, however, only have permeabilities recorded in the range of the
millidarcy (0.001 Darcy ). Reservoir permeabilities typically range between 5 and 500
millidarcies, although some reservoirs may have permeabilities exceeding 5 Darcies.
Gas, which is less viscous than crude oil, may be able to flow from tight sands or
dense limestones having permeabilities of only a few millidarcies or less.
Porosity in reservoir rocks is normally between 10% and 20%, but some excellent
reservoirs may have porosities of 30% or more. Accumulations in reservoirs with less
than about 5% porosity are usually not commercial. Porosity can be divided into
several types, as summarized in Figure 4 .
Figure 4
 Reservoir Rock Types

Sandstones usually have primary porosity, which decreases with depth of

burial as the grains are compacted and intergranular cementation
develops. However, leaching of carbonate cements and unstable minerals
in sandstones can cause good secondary porosities even at depths where
they would normally be tight.
Carbonate reservoirs are usually cemented quite early, and most lose their
primary porosity. Carbonates in petroleum reservoirs usually exhibit
secondary porosity. This may be due to solution processes, to fracturing, or
to intercrystalline pore development. Intercrystalline porosity is
particularly important in many dolomite reservoirs, where coarse
crystalline dolomite has replaced limestone. A volume reduction of up to
13% accompanies this reaction and may help to create the secondary
voids. Secondary porosities in both limestones and sandstones are often
developed by leaching along fault zones and unconformity surfaces. In
such cases, these zones may become important conduits for secondary
migration of hydrocarbons.
A small fraction of world oil reserves has been found in lithologies such as
shale or igneous and metamorphic basement rocks. In these rocks, as in
many tight, brittle sandstones and carbonates, the oil resides within
fracture porosity. Such reservoirs can be quite productive; the fractured
Monterey chert reservoirs of California are one example.
 Trapping Mechanisms

The last critical factor in the cycle of generation, migration

and accumulation is the development of a trap. A trap is a
geometric configuration of structures and/ or strata, in
which permeable rock types (the reservoir) are surrounded
and confined by impermeable rock types (the seal). In some
cases, traps may be created by hydrodynamic factors, that
is, by the movement of subsurface waters, but these are
relatively rare. Most traps fall into one of three categories
( Figure 1 ): structural traps, stratigraphic traps, or
combination traps that have both structural and
stratigraphic aspects.
Figure 1
Traps may contain oil, natural gas, or a combination of both,
with gas trapped at the highest level ( Figure 2 ).
Figure 2
Below the oil and gas columns and at the edges of the trap,
the pores of the reservoir are filled with water, which is,
with few exceptions, heavier than oil. Structural traps
( Figure 2 , (a)) are limited in size by their closure, the
vertical distance between the high and low points of the
structure. They may be full to their spill points or, as is more
common, may be less than completely full. Many
stratigraphic traps ( Figure 2 , (b)) are limited only by the
quantity of petroleum they contain. Others, however, may
be limited by the size and shape of the reservoir and by
lateral lithologic changes.
 Structural Traps

Structural traps are the most common exploration target,

since they are often relatively easy to detect and have
provided over three-quarters of the world's discovered
reserves. This is particularly true of anticlines.
Anticlines may originate in many ways, through
compression ( Figure 1 ) ,
Figure 1
or as compaction and drape features over rigid high blocks
( Figure 2 ).
Figure 2
Another type of anticlinal trap, called a rollover anticline,
forms where rapid sedimentation onto undercompacted
muds causes instability and slumping. This produces a
type of fault called a growth fault, which may also trap oil
( Figure 3 ).
Figure 3
Anticlines may occur alone or in combination with faults
( Figure 4 ).
Figure 4
These faults may or may not help produce the trap. Faults
may also be traps in their own right ( Figure 5 ); but in
either case the faults must be tight and impermeable if
petroleum is to accumulate. Usually, there is no way to
test this except by drilling.
Figure 5
Salt flow structures or diapirs can generate anticlinal traps
in the overlying sediment, as well as fault and
stratigraphic traps along their flanks ( Figure 6 ). Together,
these salt flow-related traps account for about 2% of the
world's petroleum reserves.
Figure 6
 Sratigraphic Traps

Stratigraphic traps, due to lateral and vertical changes in rock

type, account for about 13% of the world's reserves. They fall
within a wide range of categories. Some are associated with
unconformities, whether above or below them ( Figure 1 ).
Figure 1
Others are updip stratigraphic pinchouts ( Figure 2 ), within
fluctuating transgressive-regressive sequences.
Figure 2
Stratigraphic traps may also be related to diagenetic changes
( Figure 3 ), where differential solution or cementation have
caused the rock type to vary laterally.
Figure 3
Some sandstone traps are elongated bodies, either channels
or coastal barrier bars (shoestring sands) ( Figure 4 ).
Figure 4
These are usually surrounded by shales, which may act as both
source rock and seal. Carbonate reefs can form stratigraphic
traps if a high porosity is preserved or a secondary porosity is
developed ( Figure 5 ). They often occur along shelf margins,
adjacent to deeper basins where source rocks can accumulate.

Figure 5
When compared to structural traps, evidence for stratigraphic
traps is often subtle and they have historically been difficult to
find. However, seismic techniques which detail lithologic
changes have since become available to aid in the search for
stratigraphic traps.
Combination traps contain about 9% of the world's petroleum
reserves. These traps are often found in areas where faults
and folds were actively growing during deposition. In many
cases, these growing structures produced lateral changes in
sediment facies or unconformities, which helped form the
trap.
 Distribution of Trap Types

The formation of large traps concurrent with the stages of petroleum

generation and migration has been a major factor in the formation of most
giant petroleum fields (Halbouty et al., 1970). A giant field is one that
contains over 500 million barrels of recoverable oil or its gas equivalent (3.5
trillion ft3). Giant fields are of particular importance, since together they
account for over three-quarters of the world's known reserves.
An important lesson to be learned from giant petroleum occurrences is that
the timing of trap development is critical both to the presence and size of
oil accumulations. Optimal conditions for efficient migration and
entrapment occur when structures are actively growing, and stratigraphic
features such as unconformities are being created, at about the same time
as the generation and migration stage. Late-stage structures may well be
barren or may entrap only gas, since it is more easily remobilized than oil. It
is important to remember that the task of petroleum exploration is more
complicated than the simple location of subsurface traps. Even in a
petroleum-rich basin, the majority of structures that are tested will be dry.
 Seals

Traps must be sealed by impermeable

barriers in order to stop the continued
upward migration of petroleum. In the
case of anticlines ( Figure 1 ,
Figure 1
(a)), only a vertical seal, or caprock, is
required; but faults ( Figure 1 , (b)) and
stratigraphic traps ( Figure 1 , (c)) must be
sealed both vertically and laterally. Shale
is the dominant caprock of worldwide
reserves ( Figure 2 ) and is overwhelmingly
the seal in basins rich in terrigenous
sediments, where sandstones are the
dominant reservoir rock.
Figure 2
Evaporites, however, are the most
efficient caprock. They are particularly
common in carbonate-rich basins, and
they often form seals for carbonate
reservoirs. Furthermore, evaporites
commonly develop in restricted basin
settings, where accumulations of organic-
rich source rocks are also favored. Dense
carbonates are the third most abundant
caprock lithology and seal about 2% of the
world's reserves.
 Subtopic: Petroleum Exploration Overview
Basin Description and Classifications
Because of the burial and temperature requirements needed for the maturation of organic matter, most
petroleum will be found in sedimentary basins. Sedimentary basins are depressions on the earth's surface, caused
by subsidence, that receive greater-than-average sediment thicknesses.
Most basins have sediment fills in excess of 2 kilometers, and some may contain 10 or more kilometers of
sedimentary rock. This is usually sufficient for at least part of their contained organic matter to mature to
petroleum.
However, being within the "oil window" is not enough. The petroleum richness of sedimentary basins, or even
the presence of petroleum at all, is also highly dependent on source rock and reservoir development, migration
pathways, geothermal regime, style and timing of trap development, and the presence of good sealing
lithologies. The age of the sedimentary rocks within a basin is also of some importance.
Even though petroleum reserves can be found in rocks of all ages, most giant fields and most of the world's
reserves occur in sequences, of Late Mesozoic and Cenozoic age ( Figure 1 ) . Paleozoic rocks probably had
potential to generate hydrocarbons equal to that of these younger rocks, but there has been more time in which
to destroy all or part of the petroleum through uplift and erosion (Halbouty et al, 1970).
Figure 1

Petroleum enrichment, the incidence of giant fields, and the habitat of petroleum within sedimentary basins can
be related to structural, sedimentological, and geothermal settings, which can be used to describe a number of
petroleum basin types.
There are several general ways in which sedimentary basins can be grouped ( Figure 2 ).
Figure 2

They can be divided on the basis of their underlying material or crust:

· continental crust, which is relatively light, granitic and underlies most continental areas; or, · intermediate crust,
compositionally between granite and basalt and occurring along continent-ocean margins.
They may also be grouped according to the stability and movement of this underlying crust, as either; · cratonic
basins, developed on the stable parts of continents away from continental margins; · divergent-margin basins,
formed along continental margins where the sea floor is spreading and rift-drift (extensional) movements occur;
or,
· convergent-margin basins, formed along continental margins where continents and/or oceans are in collision
and some ocean crust may be consumed.
For the purpose of petroleum exploration, however, we need a finer-tuned classification scheme such as the ten-
part basin classification scheme based on the work of Huff (1980) and Klemme (1980),which is summarized in
Figure 3 .
Figure 3
Worldwide reserves can be related to their location within a petroleum basin, regardless of its basin type ( Figure
4 ).
Figure 4
Most petroleum is found along a basin's flanks, either along hinges that mark the break between the basin and
normal sediment thicknesses of the shelf, or along mobile rims. A sizeable amount of petroleum, about 18%, also
occurs in extrabasinal settings. For example, in the central United States, a regional stratigraphic high that
received thinner-than-average sediment persisted for most of the last 600 million years. Yet this region, the
Cincinnati arch, is a major petroleum province and has some giant field production.
Oil usually becomes lighter and gas more abundant with depth in most sedimentary basins. Oil also becomes
lighter and gas more prevalent laterally toward a basin's center. The heaviest crude is typically found along basin
margins. This lateral and vertical distribution of oil and gas is of considerable importance to exploration. Part of
this pattern may be attributed to increased thermal maturation with depth. However, another explanation is that
the lighter gas displaces earlier formed oil that had already accumulated in the trap (Gussow, 1954). When the
trap becomes full to its spill point, the oil is displaced and moves upward toward the basin's flanks.
 Exploration of a Petroleum Basin

Petroleum exploration can be divided into a series of critical information phases. With each step, there is a
progressively increasing data base, from which to evaluate the petroleum prospects of a region.
Phase I is the stage of early surface mapping and reconnaissance geophysics ( Figure 1 ).
Figure 1
It begins with the unexplored basin. To varying degrees, there may be some previous knowledge of surface
geology and structures. There may also have been reports of surface indications (e.g., surface seeps, springs,
asphaltic vein-fillings, gas detected in water wells, etc.) to encourage the exploration. Surface evidence of
petroleum has been important in the discovery of nearly every major onshore petroleum province in the
world (Levorsen, 1979), although there are also major areas with abundant surface evidence that have proven
to be subcommercial (e.g., Cuba and Morocco). At this stage, the geologist's role is to obtain a more detailed
knowledge of surface structures (i.e., potential traps) and evaluate other aspects critical to the exploration
task, such as sedimentary facies, continentality, and possible metamorphism. The exploration geologist must
work closely with the geophysicist to relate the surface stratigraphy and structures to the subsurface. At this
stage, a geologic analog is often used to compare the unexplored basin to other producing "look-alike" basins
which appear to have common geologic characteristics.
Phase II is the stage of seismic survey ( Figure 2 ) .
Figure 2
(This is the initial step, in offshore exploration.) During this stage, more data is obtained on the depth
configuration of potential traps and hopefully some knowledge of the character and volume of the
sedimentary fill is gained. It has generally been observed that the chances of finding commercial oil is roughly
in proportion to the total sediment volume (Levorsen, 1979), particularly if most of it lies within the depth
range of the oil and gas window (Klemme, 1980). The volume of subsurface shale (source potential) is also
evaluated. Phase III is the stage of exploratory or "wildcat" drilling, which establishes for the first time a
detailed sampling of the sediment character (reservoir, source and caprock potential), maturation, and the
geothermal regime ( Figure 3 ) .
Figure 3
The potential for a discovery exists at this stage, since the most promising prospects, usually surface or
seismically detected subsurface structures, are drilled first. However, even a dry hole is not necessarily a total
failure. It can supply a large amount of data (e.g., subcommercial shows; water-filled reservoir downdip from
a possible pinchout, etc.) that, if intelligently studied, may lead to the placement of new wildcat wells. Phase
IV, the discovery phase, follows the successful completion of some wildcat wells ( Figure 4 ) .
Figure 4
At this stage, reservoirs are established and hydrocarbon types may be linked to certain stratigraphic units
and/or trap types. Further wildcat drilling in less developed parts of the basin may be guided in part by the
play and petroleum zone concepts. A play is defined as a group of geologically similar, "look-alike" prospects,
usually at fixed horizons sharing common stratigraphic features (lithology, unconformity). A basin may also be
divisible into discrete petroleum zones. These are sediment volumes whose contained pools show several
characteristics in common. Application of the play and petroleum zone concepts usually causes the success
ratio of drilling (discovered fields/tested prospects; or bbls. found/thickness drilled) to improve during the
discovery stage. Many of the basin's largest fields will have been discovered, and exploration for more subtle
traps may commence. Phase V, the production phase, begins to provide exploration geologists with reserve
estimates and a history of the hydrocarbon potential of the basin ( Figure 5 ). There is enough information to
work out field-size distribution patterns, which may help guide further exploration as the area matures. Both
the field size of new discoveries and the success rate of drilling typically tapers off during this stage.
Figure 5
Commonly, not all of a sedimentary basin is at the same stage of drilling and development at the same time.
Part of the basin may be maturely drilled, while other areas that may have appeared initially less geologically
favored, or were less accessible, may still be only semi-mature or untested. Also, shallower depths may have
been thoroughly tested and have established production, while at the same time deeper stratigraphic
horizons may be only at the seismic survey or wildcat stages of development. It is significant that new
 Subtopic: Fundamentals of Petroleum Geology: References and
Additional Information
References
 
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