Petroleum Geoscience

PETROLEUM GEOLOGY/Overview 229

Overview

Chemical and Physical Properties

Gas Hydrates

The Petroleum System

Exploration

Production

Reserves

Overview

J Gluyas, Acorn Oil and Gas Ltd., Staines, UK

� 2005, Elsevier Ltd. All Rights Reserved.

Introduction

Petroleum geoscience is defined as the disciplines ofgeology and geophysics applied to the understandingof the origin, distribution, and properties of petroleumand petroleum-bearing rocks.

Petroleum geoscience can be described as the studyand understanding of five key components: source,seal, trap, reservoir, and timing (of petroleum migra-tion). These are sometimes known as the ‘magic fiveingredients’ without which a basin cannot become apetroleum province (Figure 1). This article examineseach of these components.

Source Rock

Petroleum (oil and gas) forms from organic matter:dead plants and animals. Burial, and thus heating ofsuch organic matter induces reactions leading to thegeneration of gas, then oil and gas, and, finally, gasalone as the temperature and residence time at hightemperature increase. Continued burial and heatingturn the residual organic matter into pyrobitumenand eventually into graphite (see Petroleum Geology:The Petroleum System).

Seal

Oil and gas are less dense than water and, followingexpulsion from the source rock, they rise towards the

Earth’s surface unless movement is arrested by a seal.Seals tend to be fine-grained or crystalline, low-per-meability rocks, such as mudstone/shale, cementedlimestones, cherts, anhydrite, and salt (halite). Sealscan also develop along fault planes, faulted zones,and fractures.

The presence of seals is critical for the developmentof petroleum pools. In the absence of seals, petroleumwill rise to the Earth’s surface and be destroyed.Although seals are critical for the development ofpetroleum pools, none are perfect. All leak. Combin-ations of regionally extensive seals and underlyingreservoir complexes are commonly referred to as‘plays’, and the areas within which the quality ofseals and reservoirs is such that petroleum accumula-tions could occur (given an appropriate trappingconfiguration) are commonly referred to as ‘play fair-ways’.

The most common subdivision of seals distin-guishes between seals in which petroleum is unableto force its way through the largest pores (membraneseals) and seals in which petroleum can escape onlyby creating fractures (hydraulic seals). Attributeswhich favour a rock as a seal include a small poresize, high ductility, large thickness, and wide lateralextent. The physical properties of the water and pet-roleum are also important. Water salinity, petroleumdensity, and interfacial tension between petrol-eum and water are the most important, and theseproperties will change according to changing pressureand temperature conditions.

The most common lithology that forms a petroleumseal is mudrock. Mudrocks are composed of eithercarbonate or siliciclastic minerals (or both), andmudrock sequences are often thick (>50 m) and lat-erally continuous (>1.0 km2). Examples of mudrockseals are found in all deltaic settings (including theGulf of Mexico, Niger, and Nile Delta petroleum

PETROLEUM GEOLOGY

Contents

Figure 1 Diagram of a cross-section of a petroleum-bearing basin, illustrating the five key components: source rock, seal, reservoir,

trap, and petroleummigration. Reproduced from Gluyas JG and Swarbrick RE (2003) Petroleum Geoscience. Oxford: Blackwell Science.

230 PETROLEUM GEOLOGY/Overview

provinces) and many interior, rift, and passive contin-ental margin basins (including north-west Australianshelf, north-west Europe, North Sea, and south-eastAsia). Halite can form a more effective seal, but is arelatively rare lithology found only where conditionsof high evaporation of seawater have taken place. TheUpper Permian rocks of north-west Europe containZechstein halite that is known to have trapped gas forlong periods of geological time. Halite forms part ofthe sealing lithology in many of the large Middle Eastpetroleum accumulations.

Figure 2 A pressure vs. depth plot, illustrating a typical water

gradient (aquifer) supporting a petroleum column, whose steeper

gradients lead to a pressure difference (Pb) at its maximum

beneath the seal. Reproduced from Gluyas JG and Swarbrick

RE (2003) Petroleum Geoscience. Oxford: Blackwell Science.

Membrane Seal

When petroleum is trapped beneath a seal, there is abuoyancy pressure (Pb). The magnitude of the buoy-ancy pressure is a function of the contrast in densitybetween the water (rw) and petroleum (rp), and itsheight (h) above the free water level where both are inequilibrium (normally close to the petroleum–watercontact). The relationship can be written as

Pb ¼ ðrw � rpÞh

where Pb is expressed in units of pressure (e.g., bar,psi, MPa) and the fluid densities are expressed aspressure gradients (e.g., bar m�1, psi ft�1, Pa m�1)(Figure 2). The maximum petroleum column is

controlled by the capillary entry pressure of thepetroleum into the largest pores in the seal. The capil-lary entry pressure (Pd) of a water-wet rock is given bythe equation

Figure 3 A schematic illustration of a pore throat between two

grains. The radius of the pore throat and the buoyancy pressure,

plus the interfacial angle and surface tension between oil and

water, determine whether oil can migrate through the pore throat

or remain trapped beneath. Reproduced from Gluyas JG and

Swarbrick RE (2003) Petroleum Geoscience. Oxford: Blackwell

Science.


Pd ¼ 2g cos y=R

where g is the interfacial tension between the waterand the petroleum, y is the contact angle, and R is theradius of the largest pore (Figure 3). The interfacialtension and contact angle change with increasingtemperature and pressure and are related to fluidtype and density. These properties are routinely estab-lished from laboratory experiments on rocks. The sealcapacity determines the height of a petroleum columnthat can be trapped beneath it, and the seal will bebreached when the buoyancy pressure (Pb) exceedsthe seal capillary entry pressure (Pd).

Figure 4 The relative magnitudes of the three principal

stresses, one vertical (v) and two horizontal (H, h), acting in a

rock mass, and the associated direction of shear, for normal

strike-slip and reverse faulting regimes. Reproduced from

Gluyas JG and Swarbrick RE (2003) Petroleum Geoscience. Oxford:

Blackwell Science.

Hydraulic Seal

When the capillary entry pressure of the rock is ex-tremely high, for example in evaporites, the failure ofthe seal is controlled by the strength of the rock that,if exceeded, creates natural tension fractures (see Tec-tonics: Faults; Fractures (Including Joints)). The rockwill fracture when the pore pressure is greaterthan both the minimum stress and the tensile strengthof the rock. Structural geologists describe the stressesin rock in terms of three orthogonal components ofstress (Figure 4), one oriented vertically (Sv) and theother two oriented horizontally (Shmin and Shmax). Inrelaxed sedimentary rocks found in an extensionalbasin or a young delta, Sv is usually greater than bothShmin and Shmax, and so the minimum stress (s3) is hori-zontal. Under these conditions, the rock will fracture bycreating vertically oriented fractures which will propa-gate horizontally. In rocks under horizontal push, orcompression, the vertical stress (Sv) is the minimumstress (s3), and the rock will fail by the opening ofhorizontal fractures.

Fault

Faults can act as both conduits (migration pathways)and seals, depending on the hydraulic conditions, therock properties of the faults, and the properties of the


rocks juxtaposed across the faults. The considerationof faults as seals follows the same reasoning as forcap-rock seals above, i.e. the sealing capacity of afault relates to its membrane strength and hydraulicstrength. Membrane fault seals fail when the pressureof the petroleum can exceed the entry pressure of thelargest pores along the fault plane. Hydraulic faultseals fail when the fault is opened mechanically byhigh pore pressure which exceeds the minimumstress.

Reservoir

For a rock to be a petroleum reservoir, it need onlybe porous, i.e., capable of holding petroleum, andpermeable, i.e., able to flow petroleum.

Intrinsic Properties

The following properties must be known or estimatedin order for the petroleum volume to be calculated.

1. Net to gross.2. Porosity.3. Permeability.4. Petroleum saturation.

The question regarding whether any discovered pet-roleum will flow from its reservoir into the well bore isonly partially addressed in exploration. This is com-monly because permeability estimations are rarelyaccurate.

Figure 5 Net to gross is the ratio between reservoir rock capa

commonly defined using a single permeability cut-off. The example h

metres of sandstone was cut in one core, but only 19m had a permea

Reproduced from Gluyas JG and Swarbrick RE (2003) Petroleum Geo

Net to gross Net to gross is a measure of the poten-tially productive part of a reservoir, commonly ex-pressed as the percentage of producible (net) reservoirwithin the overall (gross) reservoir package (Figure 5).The percentage net reservoir can vary from just a fewper cent to 100%. Net pay is used to describe thepetroleum-bearing net reservoir.

It is common to define net sand (or limestone)using a permeability cut-off (typically 1 mD for gasand 10 mD for light oil). Such information on per-meability is only available when the reservoir hasbeen cored or a petroleum flow test completed.For uncored intervals and uncored wells, a combin-ation of data on lithology and porosity from wirelinelogs is used. These data are calibrated to permeabi-lity data in a cored interval (see Petroleum Geology:Exploration).

Porosity Porosity is the void space in a rock (Figure 6).It is commonly measured as a volume percentage (seeSedimentary Rocks: Sandstones, Diagenesis and Poros-ity Evolution). In the subsurface, this volume may befilled with petroleum, water, a range of non-hydrocar-bongases (CO2,H2S,N2),or somecombinationof these.Most reservoirs have porosities in the range 20–30%.

Not all pores are alike; there are big pores andlittle pores, pores with simple shapes, and otherswith highly complex three-dimensional morpholo-gies. A knowledge of the size and shape of the poresand the way in which they are interconnected is

ble of flowing petroleum and the gross reservoir interval. It is

ere is a Jurassic oil-bearing sandstone from the North Sea. Thirty

bility greater than the 10mD cut-off chosen, a net to gross of 63%.

science. Oxford: Blackwell Science.

Figure 6 Scanning electron photomicrograph of a porous

(28%) and permeable (2200mD) Permian, Rotliegend reservoir

sandstone, southern North Sea. Field of view, 2.7mm� 1.8mm.

Photograph by A. J. Leonard, reproduced from Gluyas JG

and Swarbrick RE (2003) Petroleum Geoscience. Oxford: Blackwell

Science.

Figure 7 Porosity in sandstones. (A) Intergranular porosity

(arrowed) between quartz grains with quartz overgrowths, Juras-

sic Brent sandstone, northern North Sea. Field of view,

1.3mm� 0.9mm. (B) Intragranular porosity within partially dis-

solved feldspar, Permian Rotliegend sandstone, southern North

Sea. Field of view, 650mm� 450mm. (C) Microporosity (arrowed)

between illitized kaolinite plates, Jurassic Brent sandstone,

northern North Sea. Photographs by J. G. Gluyas.


important, because it is these factors that determinethe permeability of the rock.

For sands and sandstones, a threefold descriptionof porosity is used: intergranular, intragranular, andmicroporosity (Figure 7). Intergranular porosityoccurs between grains. Individual pores in cleansand will occupy approximately 40% of the totalvolume. For coarse sands, the pores are larger thanin fine sands. In most sandstones, the intergranularporosity is primary, a residuum of that imparted atdeposition. Some intergranular porosity may becreated in sandstones by the dissolution of mineralcements. Most intragranular porosity is secondary inorigin, created on partial dissolution of grains.Microporosity simply means small pores, those asso-ciated with depositional or diagenetic clay or othermicrocrystalline cements.

Porosity development in limestones and dolomitesis much more variable than that for sandstones. Bothrock types are much more prone to mineral dissol-ution and precipitation than sandstones. This,coupled with the often varied suite of shell andother bioclastic material in the carbonates, makesfor a wealth of pore types (Figure 8): intergranular,intragranular, intercrystalline, intracrystalline, bio-mouldic, vuggy, fracture, cavernous. The size rangefor pores is also much greater for limestones than forsandstones: from micropores (a few micrometres) inindividual oolite grains to giant cave systems.

Permeability Permeability is an intrinsic property ofa material that determines how easily a fluid can passthrough it. In the petroleum industry, the darcy (D) is

the standard unit of permeability, but millidarcies(mD) (1 mD¼ 10�3 D) are more commonly used.A darcy is defined as a flow rate of 10�2 m s�1 for afluid of 1 cP (centipoise) under a pressure of10�4 atm m�2. Permeability in reservoir rocks mayrange from 0.1 mD to more than 10 D. Permeability

Figure 8 Porosity systems in carbonate reservoirs. (A) Intergranular porosity in limestone, beach rock, Bahamas. Reproduced from

Bathurst RGC (1976) Carbonate Sediments and Their Diagenesis, Developments in Sedimentology 12. Oxford: Elsevier. (B) Intercrystalline

porosity within dolomitized limestone, Permian Zechstein reservoir, southern North Sea, Dutch sector. Field of view,

3.25mm� 2.50mm. Photograph by J. G. Gluyas. (C) Biomoldic porosity within algal and mollusc moulds, Pennsylvanian limestone,

Texas. Field of view, 5mm� 4mm. Reproduced with permission from Dickson JAD and Saller AH (1995) Identification of subaerial

exposure surfaces and porosity preservation in Pennsylvanian and Lower Permian shelf limestones, eastern central Basin Platform,

Texas. In: Budd DA, Saller AH, and Harris PM (eds.) Unconformities and Porosity in Carbonate Strata, American Association of Petroleum

Geologists Memoir 63, pp. 239–258. Tulsa, OK: American Association of Petroleum Geologists. (D) Vuggy, oil-stained porosity within

Cretaceous Bangestan limestones, Zagros Mountains, Iran. Field of view, 10 cm� 8 cm. Photograph by J. G. Gluyas.


measurements made at the Earth’s surface are com-monly greater than those in the subsurface, and apressure correction must be made to restore the valueof permeability to reservoir conditions. This intrinsicrock property is called the absolute permeability whenthe rock is 100% saturated with one fluid phase.

Water, oil, and gas saturation It is rare in nature tofind a reservoir entirely oil (or gas) saturated. Morecommonly, the pore system contains both oil andwater. The proportions of each phase are commonlyexpressed as percentages linked to the abbreviations:Sw for water, So for oil, and Sg for gas. Water andpetroleum saturations are not constant across a reser-voir. They vary in response to the position in the oilcolumn, the permeability of the rock, and the miner-alogy of the rock. Oil and water saturations will alsochange as petroleum is produced.

Reservoir Lithologies

Sandstone and limestone (including dolomite) are themost common reservoir lithologies. Sandstones dom-inate as important reservoirs in the USA (includingAlaska), South America, Europe, Russian Asia, northAfrica, and Australia. Limestones form the dominantreservoirs in the Middle East. They are also important

in the Far East, western Canada, and some of theformer Soviet states.

Sandstones, limestones, and dolomites of any agecan make fine reservoirs. However, most of the bestreservoirs in the world are relatively young. Petroleumfields are more common in Cenozoic and Mesozoicsediments than in Palaeozoic reservoirs. Precambrianage reservoirs are rare. There is no intrinsic reasonwhy old rocks are more or less likely to be reser-voirs than younger ones; it is simply that olderreservoirs have had greater chance to be involved intectonism or cementation, so destroying their porosityor permeability.

In addition to sandstone and limestone, fracturedrock of any type can form a reservoir. The fracturesalone may form the total pore volume of the reservoir.Alternatively, the fractures may help drain petroleumfrom the intervening lower permeability rock.

Reservoir; sandstone depositional systems Sediments,including those which may one day form a petroleumreservoir; can accumulate in many environments onthe Earth’s surface (see Sedimentary Environments:Depositional Systems and Facies). This includessands deposited both on land and beneath the sea(Table 1). The overall architecture and internal

Table 1 Clastic reservoirs

Depositional

system

Architectural

elements Size range Reservoir properties Example oil/gas field(s) or province

Alluvial fan Low-angle half

cones, linear

and sheet

sand bodies

1–10 km diameter Heterogeneous, poorly sorted Quiriquire Field, Pliocene

E. Venezuela, 750mmbbl

Aeolian

deposit

Dune, sand

sheet

100s km2

Dune well-sorted porous sands

high quality sandsheet

moderate quality

Permian Rotliegend, Europe; Jurassic

Norphlet, US Gulf Coast

Lake

deposit

Half cone (fan) Few km diameter Poor to good, function of sediment

input

Thailand & China

Fluvial

system

Channel fill,

crevasse

splay

Channel belts 10s

km � few km,

crevasse splay

few km diameter

Channel fills in braided and

meandering systems commonly

good; braided net to

gross>meandering net to

gross

Prudhoe Bay Field, Triassic Alaska,

>10 bn bbl; Wytch Farm Field,

Triassic UK onshore, 300mmbbl

Delta and

coastline

Channel

mouthbar,

shoreface,

beach

Figure 9 Commonly good in reworked

sandstones, variable net to

gross

Niger Delta, W. Africa; Brent system,

North Sea; Mahakan Delta,

Indonesia; multiple billion barrels

fields

Shallow

marine

Shoreface to

offshore

sandstone

bars

Figure 9 Good to excellent, high net to

gross

Shannon Sandstone, Cretaceous USA;

Fulmar/Ula Sandstones, Jurassic

UK and Norwegian North Sea; Toro

Sandstone, Jurassic/Cretaceous

Papua New Guinea

Deep

marine

Fan lobe, fan

channel

10 –100s km long,

10s km across

Depends upon sediment source

area

Tertiary formations, North Sea; Plio-

Pleistocene US Gulf Coast; Tertiary

Congo Fan

bn bbl, billion barrels; mmbbl, million barrels.


geometry of the sand bodies (Figure 9) control theperformance of a reservoir during petroleum produc-tion (see Petroleum Geology: Production).

Reservoir; carbonate depositional systems Lime-stones and dolomites form some of the largest petrol-eum reservoirs in the world. Many of the largest occurin the Middle East. Other areas in which carbonatereservoirs deliver large quantities of oil and gas arewestern Canada, Mexico, Texas (USA), Norway (cen-tral North Sea), Poland, Kazakhstan, western andsouth-eastern China, Iran, and Libya.

The sediment that forms most carbonate reservoirsaccumulated in shallow marine environments (seeSedimentary Environments: Carbonate Shorelinesand Shelves). The important exceptions are pelagicchalks (Ekofisk Complex of the North Sea) and deep-water resedimented carbonates of the Poza RicaTrend in Mexico.

Like their clastic counterparts, there is a clear linkbetween the reservoir potential of a carbonate bodyand the environment in which the host sediment ac-cumulated. High-energy ooid and shell shoals canmake excellent reservoirs. Framework reef complexesare also prime reservoir targets. However, unlike sili-ciclastics, carbonates can undergo almost completetransformation on weathering and/or diagenesis to

produce reservoirs from former seals and seals fromformer potential reservoirs.

Dolomite (see Sedimentary Rocks: Dolomites) Pro-ducing dolomites range in age from Precambrian toTertiary. It is estimated that about 80% of the recov-erable petroleum in carbonate-hosted reservoirs ofthe USA occurs in dolomite and only about 20% inlimestone. The same ratio probably applies to theproducible reservoirs in the Permian Zechstein ofEurope, whilst older carbonate plays in Europe andRussian Asia are almost wholly dolomite. The dolo-mitization of limestones commonly leads to an in-crease in both porosity and permeability (Figure 10).

Karst (see Sedimentary Processes: Karst and Palaeo-karst) Karstified limestones and dolomites representthe second major group of carbonate reservoirs notdirectly linked to depositional environments. Karst isa product of mineral dissolution (Figure 11). It de-velops where carbonates are exposed to meteoricwater, often linked with episodes of sea-level fall.Karst features are well known to geologists and geog-raphers alike: caves, collapse breccias, dissolution-enhanced joints and fractures, and vugs.

Fields producing from karstified limestones anddolomites include the Liuhua Field in the South China

Figure 9 The average size, shape, and location of sand bodies in wave, tidal, and fluvially influenced reservoirs. Reproduced from

Reynolds AD (1994) Sequence stratigraphy and the dimensions of paralic sandstone bodies. In: Johnson SD (ed.) High Resolution

Sequence Stratigraphy: Innovations and Applications, pp. 69–72. Liverpool: Liverpool University.


Sea, the Permian reservoirs of Texas and New Mexico,and parts of the Upper Permian in the Zechstein Basinin Europe. Thermal karst, produced when hot fluidsdissolve limestones at depth, may also become reser-voirs. The Albion Scipio Field of Michigan is of thistype.

Figure 10 A comparison of porosity and permeability for dolo-

mitized and undolomitized oolite, Cretaceous Middle East. Re-

produced from Gluyas JG and Swarbrick RE (2003) Petroleum

Geoscience. Oxford: Blackwell Science.

Trap

Trap is the term to describe the body, bounded by sealsand containing reservoir, in which petroleum can accu-mulateas itmigrates fromthe source rock to theEarth’ssurface. There are many different trap geometries.These can be grouped into three categories: structural,stratigraphical, and hydrodynamic (Table 2). Struc-tural traps are created by tectonic, diapiric, compac-tional, and gravitational processes (Figure 12). Almostthe entire world’s discovered petroleum is in trapsthat are largely structural. Stratigraphical traps are


formed by lithological variations or property vari-ations generated by alteration of the sediment or fluidthrough diagenesis (Figure 13). Much of the world’sremaining undiscovered petroleum will be found instratigraphical traps. Purely hydrodynamic traps arerare. Such traps rely on the flow of water through thereservoir horizon to ‘drag’ the petroleum into a favour-able trapping configuration, such as the plunging nose

Figure 11 Tower karst containing fracture and cavernous por-

osity, Palaeozoic limestones, Zhaoquing, Guangdong Province,

China. Photograph by J. G. Gluyas.

Table 2 Structural and stratigraphical traps

Structural Tectonic

Diapiric

Compactional

Gravitational

Stratigraphical Depositional

Diagenetic

of a fold. The trapping mechanism for many fields iscommonly a combination of structural and strati-graphical elements or, more rarely, structural elementsand hydrodynamic conditions.

Structural Trap

Compressive tectonic regimes commonly lead to thedevelopment of large-scale contractional folds andthrusts. This is common at convergent plate boundar-ies and transpressional strike-slip plate boundaries(wrench systems). The El-Furrial Trend of easternVenezuela is an example of such a system. The anti-clinal traps of the trend were developed during con-vergence of the Caribbean and South American platesduring the Neogene. Many of the traps are large rampanticlines (Figure 14). They have oil columns of, onaverage, 400 m and reservoirs formed from high netto gross shallow marine sandstones.

In North America, thrust-linked rollover anticlinesform the major trap type in the Wyoming–Utah thrustbelt fields and the southern foothills of the AlbertaBasin, Canada. Compressional anticlines also formgiant traps within the Zagros fold belt of Iran.

Traps formed by extensional tectonics are commonin rift basins. The East Shetland Basin of both the UKand Norwegian sectors of the North Sea containedabout 15 billion barrels of recoverable oil. Much ofthis oil was trapped in tilted fault blocks formedduring Late Jurassic rifting. In the pre-rift section, oilis reservoired in the sandstones of the Middle JurassicBrent Group, together with other sandstones of bothJurassic and Triassic age (Figure 15). Traps formedthrough tectonic extension are also important in theGulf of Suez, the Haltenbanken area, offshore mid-Norway, and in the pre-rift sections of the GippslandBasin (Australia).

Traps can also be formed by diapiric processes. Thespecific gravity of salt (halite) is about 2.2 g cm�3 andthat of fully consolidated rock is about 2.5–2.7 g cm�3.Thus salt is buoyant relative to most other sediments

Extensional

Compressional

Salt movement

Mud movement

Drape structures

Listric fault movement

Pinchouts (dunes, bars, reefs, channels, etc.)

Unconformities (erosional, subcrop, karst, etc.)

Mineral precipitation

Mineral dissolution (thermal karst, dolomitization)

Tar mats

Permafrost

Gas hydrate crystallization

Figure 12 Structural traps. (A) Tilted fault blocks in an extensional regime. The seals are overlying mudstones and cross-fault

juxtaposition against mudstones. (B) Rollover anticline on thrust. Petroleum accumulations may occur on both the hanging wall and

the footwall. The hanging wall accumulation is dependent on a subthrust fault seal, whereas at least part of the hanging wall trap

is likely to be a simple, four-way, dip-closed structure. (C) Lateral seal of a trap against a salt diapir and compactional drape trap over

the diapir crest. (D) Diapiric mudstone associated trap with lateral seal against mud wall. Diapiric mud associated traps share

many common features with that of salt. In this diagram, the diapiric mud wall developed at the core of a compressional fold.

(E) Compactional drape over a basement block commonly creates enormous low-relief traps. (F) Gravity-generated trapping

commonly occurs in deltaic sequences. Sediment loading causes gravity-driven failure and produces convex-down (listric) faults.

The hanging wall of the fault rotates, creating space for sediment accumulation adjacent to the fault planes. The marker beds (grey)

illustrate the form of the structure that has many favourable sites for petroleum accumulation. Reproduced from Gluyas JG and

Swarbrick RE (2003) Petroleum Geoscience. Oxford: Blackwell Science.


and sedimentary rocks. Over geological time, saltdeforms plastically. With loading caused by continuedsedimentation, layers of salt may aggregate into swellsand eventually pillows. Subsequently, a salt diapir mayrise through the overburden. Very similar processes tothose associated with salt diapirism can occur in asso-ciation with muds. Rapidly deposited muds are com-monly water rich, overpressured, and, in consequence,highly mobile. Mud lumps (Niger Delta), shale walls,diapirs, and mud volcanoes (Trinidad, Azerbaijan) areall products of mass mud movement.

Diapiric movement of both salt and mud cancreate anticlinal structures that could form petroleumtraps. Trap configurations can also develop in theareas of salt withdrawal. The ‘turtle’ structure anti-cline develops via increased sedimentation in areasof salt withdrawal. Later, as salt continues to feedthe diapir, the structure flounders and flips into ananticline.

Greater Burgan (Kuwait), the second largestoilfield in the world (>75 billion barrels of reserves),developed over a large, low-amplitude salt swell.

Figure 13 Stratigraphical traps. (A) ‘Reef’ oil is trapped in the core of the reef, with fore-reef talus and back-reef lagoonal muds

acting as lateral seals and basinal mudstones as top seals. (B) Pinchout (sandstone) trap within stacked submarine fan sandstones.

The upper surface of the diagram shows the plan geometry of a simple fan lobe. Lateral, bottom, and top seals are the surrounding

basinal mudstones. (C) Channel-fill sandstone trap. The oil occurs in ribbon-shaped sandstone bodies. The top surface of the diagram

shows the depositional geometry of the sandstone. Total seal may be provided by interdistributary mudstones or a combination of

these and marine flooding surfaces. (D) Shallow marine sandstone bar completely encased in shallow marine mudstone. The upper

surface of the diagram shows the prolate bar. (E) Subunconformity trap. The reservoir horizon is truncated at its up-dip end by an

unconformity and the sediments overlying the unconformity provide the top seal. Lateral and bottom seals, like the reservoir interval,

pre-date the unconformity. (F) Onlap trap. A basal or near-basal sandstone onlaps a tilted unconformity. The sandstone pinches out on

the unconformity and is overstepped by a top seal mudstone. Reproduced from Gluyas JG and Swarbrick RE (2003) Petroleum

Geoscience. Oxford: Blackwell Science.


Similar, simple anticlinal dome traps typify theCretaceous Chalk fields of the Norwegian NorthSea. As with the Middle East examples, the keycontrolling structures are the underlying salt pillows.

Traps associated with diapirs rather than swellstend to be much smaller in aerial extent than the giantsdescribed above. They also tend to be much morestructurally complex, commonly containing bothradial and concentric fault patterns. The MacharField (STOOIP (standard barrels of oil originally inplace) about 228 mmstb) of the North Sea is roughlycircular in outline with a diameter of about 4 km(Figure 16).

Anticlinal traps created through compaction occuracross basement highs, tilted fault blocks, carbonateshelf rims, reefs, or isolated sand bodies. Some of thesimplest are also the largest. The world’s biggest field,Ghawar in Saudia Arabia, is such a trap. Oil occurs inJurassic carbonates draped over and compactedaround a north–south-trending basement high.

Traps formed by gravity-driven processes are par-ticularly important in large recent deltas. The best-described examples are from the US Gulf Coast andWest African deltas (Niger, Congo). The gravitystructures form independently of basement tectonicsand owe their existence to shallow detachment along

Figure 14 El Furrial Trend, eastern Venezuela. The petroleum traps are large rollover anticlines on the hanging walls of thrusts.

Most are four-way, dip-closed structures, whilst some have a dependence on a fault component along their south-eastern thrust

margin. Reproduced from Gluyas JG and Swarbrick RE (2003) Petroleum Geoscience. Oxford: Blackwell Science.


low-angle, basinward-dipping planes. The drivemechanism is provided by the weight of sedimentdeposited by the delta at the shelf–slope break or onthe slope itself. In the Niger Delta, the detachmentplanes are highly mobile muds, whereas, in the GulfCoast (Mississippi Delta), detachment occurs on bothmuds and the Louanne Salt (Jurassic). The key de-tachment surfaces are commonly listric, concave-up, and concave-basinward in plan view. The mainfaults are commonly large, being tens of kilometrestip to tip.

Stratigraphical Trap

From top to bottom of a systems tract, each depos-itional environment is capable of producing a juxta-position of permeable and impermeable sedimentswhich might one day form a stratigraphical trap for

petroleum. In practice, the reservoir geometry be-comes the trap geometry. Examples include aeoliandunes encased in lacustrine mudstone, sand-filled flu-vial channels cut into mud-rich overbank deposits,shallow marine bar sandstones surrounded by marineshales, carbonate reefs isolated by enclosing marls,and submarine fan sands trapped within the domainof pelagic mud.

The Paradox Basin (Colorado and Utah, USA) con-tains a large array of small oil and gas fields in strati-graphical pinchout traps. Devonian reservoirs occurwithin shallow marine bar sandstones and Carbon-iferous reservoirs within carbonate mounds. TheParadox Basin traps are difficult to find, but haverelatively simple shapes. Their geometries are eitherprolate bar forms or more equidimensional carbonatemounds. Pinchout traps formed in deltaic settings areoften much more complex in outline and, because

Figure 15 UK and Norwegian Brent Province. The elongate shapes reflect the geometry of the tilted fault blocks that form the traps.

The reservoir is largely Middle Jurassic Brent sandstones together with Triassic and Upper Jurassic sandstones in some fields. The

traps for neither Troll (Upper Jurassic reservoir in low-relief anticline) nor Agat (Lower Cretaceous reservoir, stratigraphically

trapped) are tilted fault blocks. Reproduced from Gluyas JG and Swarbrick RE (2003) Petroleum Geoscience. Oxford: Blackwell Science.


potential reservoir sandstones are commonly discon-tinuous, multiple pools (clustered fields) are common(Figure 17).

Attenuation of the up-dip portions of a potentialreservoir interval by an unconformity can create

massive traps with enormous petroleum catchment(drainage) areas. The largest oilfield in North Amer-ica, Alaska’s Prudhoe Bay, is an unconformity trap. Ithas about 25 billion barrels of liquid and more than20 trillion cubic feet of gas in place. East Texas, the

Figure 16 A structural cross-section of the Machar Field, central North Sea, showing the circular outline of the field and the

distribution of reservoirs around the head of the salt diapir. Reproduced from Foster PT and Rattey PR (1993) The evolution of a

fractured chalk reservoir: Machar Oilfield, UK North Sea. In: Parker JR (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th

Conference, pp. 1445–1452. London: Geological Society.


largest oilfield in the USA Lower 48, is also a strati-graphical trap. The productive Woodbine Sandstonereservoir, with its initial reserves of about 6.8 billionbarrels, is sandwiched between two unconformities.The sand rests upon the Washita Group mudstonesand is itself truncated beneath the Austin Chalk. Thefield, some 40 miles long and 5 miles wide, is a simplehomoclinal dip to the west.

Each of the unconformity traps described aboverelies on a combination of trapping mechanisms,which rely in large part on a planar or gently foldedunconformity. Unconformities come in a variety ofshapes. The most spectacular of the unconformity-bounded traps are those commonly referred to as‘buried hills’. Such hills are residual topography of aone-time land surface. Thus it is the unconformitysurface that has the trapping geometry (Figure 18).Buried hill traps are most common in karstified areas,such as northern China.

Mineral cements are known to form top, lateral,and even bottom seals to reservoirs. Examples incarbonate systems are more numerous than those inclastic systems. In the Albion-Scipio Field ofMichigan (USA), all surrounding rock to the trapis thoroughly cemented limestone and dolomite.A comparable situation exists for many of thecarbonate-hosted oilfields of Abu Dhabi; porosityonly exists where there is oil. Areas that at one timemust have been the aquifers to the oilfields havebeen thoroughly cemented. For a few fields, suchcementation has allowed trap integrity to be main-tained despite tilting of the field after petroleum ac-cumulated.

Tar mat seals are common in the shallow subsur-face. They also act as cap rock for the largest singleaccumulation of heavy (viscous) oil in the world; theFaja of south-eastern Venezuela, which has about 1.2trillion barrels of oil in place. Tar seals and tar sands

Figure 17 Paralic field outlines commonly have complex

shapes because of the interaction between structure and sedi-

ment bodies. This complexity is multiplied because individual

paralic sandstones tend to be stacked. The four examples


are also common within the Western Canada Basinand Californian basins.

Gas trapped beneath permafrost forms large fieldsin the northern part of the West Siberia Basin, adja-cent to the Kara Sea. In cold regions, gas (methane) isalso trapped as gas hydrate.

Hydrodynamic Trap

The idea that moving water could and would controlthe distribution of both oil and gas traps was firstadvocated in 1909. The hypothesis had a numberof supporters until the 1930s, when the number ofpublications on the topic dwindled and the anti-clinal theory of petroleum accumulation reassumedits position as the only favoured theory. Twenty yearslater, the idea was resurrected, although it remainscontroversial.

Those traps with undoubted hydrodynamic creden-tials tend to be in foreland basins where subsurfacereservoir units commonly crop out in adjacent moun-tain belts. The outcropping reservoir units are re-charged with meteoric water and the hydraulic headdrives the flow through the basin. Two of the best-documented examples are the Frannie Field of theBig Horn Basin, Wyoming, and the East Colinga Ex-tension Field of San Joaquin Valley, California. Inboth instances, there is sufficient information tomap the tilted oil–water contacts, rule out the pos-sibility of significant permeability barriers in thesystems, and explain the water flow in terms ofthe adjacent topography and subsurface structure.

Migration

Migration is the process (or processes) whereby pet-roleum moves from its place of origin, the sourcerock, to its destruction at the Earth’s surface. Alongthe route, the petroleum’s progress may be temporar-ily arrested and the petroleum may accumulate withina trap. The timing of trap formation relative to that ofpetroleum generation and migration is critical. Thetrap has to form at the same time or earlier thanpetroleum migration if it is to capture petroleum.

Migration may be divided into three stages(Figure 19).

show: (A) field shape on a simple faulted anticline for which the

reservoir interval is much larger than the anticline; (B) the same

structure as in (A), but with the reservoirs developed in channel

and crevasse splay sandstones that are smaller in area than the

structure; (C) the same structure as in (A), but with mouthbar

sandstones which are also smaller than the structure; (D) a

combination of channel and mouthbar sandstones at different

levels. A. Reynolds, personal communication, 1994. Reproduced

courtesy of BP.

Figure 18 Subunconformity trap beneath the base Cretaceous unconformity, Buchan Field, UK North Sea (fractured Devonian

sandstone reservoir). Reproduced from Abbots IL (1991) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume, Geological

Society Memoir No. 14. London: Geological Society.

Figure 19 Diagram of the three stages of migration. Primary

migration out of the source rock and into a trapped reservoir

(reservoir 2) or a carrier bed (reservoir 1). Secondary migration

in carrier reservoir 2 and up faults into reservoir 3. Tertiarymigra-

tion (dissipation) from reservoir 3 to the surface. Reproduced from

Gluyas JG and Swarbrick RE (2003) Petroleum Geoscience. Oxford:

Blackwell Science.


. Primary migration: expulsion of petroleum fromthe source rock.

. Secondary migration: the journey from source rockto trap.

. Tertiary migration: leakage and dissipation of thepetroleum at the Earth’s surface.

Primary Migration

There have been many hypotheses created to ex-plain the migration of petroleum out of the sourcerock. Most researchers now favour processeswhereby petroleum is expelled from the source rockas a separate phase within a water-wet rock matrix.

Analyses have been performed on a source rock(Kimmeridge Clay, North Sea) which is activelyexpelling petroleum. The aim was to elucidate theprecise primary migration mechanisms. The analyt-ical results could best be explained by invoking pres-sure-driven flow of a petroleum-rich phase as themain expulsion mechanism for source rocks. Specif-ically, it was demonstrated that petroleum was firstexpelled when the volume of generated petroleumapproximately matched the volume of pore spacewithin the mudstone. That is, the mudstone wasalmost fully saturated with petroleum before expul-sion occurred. This supported earlier observations onlean source rocks. Those which yield less than 5 kgpetroleum per tonne tend not to achieve sufficientsaturation for expulsion to occur.

Gas expulsion may occur in a similar fashion tothat of oil, albeit at higher temperatures. Clearly, thevolume increase associated with gas generation is

massive, be it directly from kerogen or from thethermal decomposition of previously formed oil.Pressure-driven expulsion will occur either through


the existing pore network or through induced frac-tures. During gas generation, previously generated,short-chain liquid hydrocarbons may become dis-solved in the gas and expelled with it. This mechan-ism has been used to explain the production ofcondensate from Type III kerogen in overpressuredmudstone.

Secondary Migration

Secondary migration takes petroleum from the sourcelocation to trap or traps via carrier beds. The definingaspect of secondary migration is that it concentratesor focuses the petroleum. On escape from the sourcerock, petroleum is dispersed over a large area. By thetime petroleum reaches the relatively restricted areaof a trap, it can occupy more than 90% of the porevolume in the reservoir. Secondary migration is tem-porarily arrested once the migrating petroleum entersa trap. Disruption of the trap or overfilling of the trapcan lead to remigration of the petroleum to a higherstructural level under the same secondary migrationprocess. Such secondary migration ends when petrol-eum approaches the Earth’s surface.

The medium through which the petroleum travelsduring secondary migration is also quite differentfrom that of the source rock. The pore size and thuspermeability in a carrier bed, be it a sandstone, car-bonate, or fractured lithology, is much larger thanthat in a source rock. The driving mechanism forsecondary migration is the density difference betweenthe petroleum (less dense) and water (more dense).The density difference is expressed through the buoy-ancy force generated by the pressure difference be-tween a point in a continuous petroleum column andthe adjacent pore water.

The restricting force to petroleum migration is thecapillary injection pressure. A slug of petroleum mi-grates from pore to pore in a carrier bed, squeezingthrough the intervening pore throats. The force re-quired to move petroleum through a pore throat is afunction of the radius of the pore throat, the interfacialtension between the petroleum and the water, and thewettability of the rock–petroleum–water system.

The buoyancy effect means that petroleum willtend to rise within the sediment column. The capillaryeffect dictates that, in the absence of other forces,petroleum will migrate from small pores to largepores. Furthermore, petroleum (and water) will at-tempt to equilibrate with respect to pressure. That is,flow can be induced by pressure differential (eitheroverpressure or hydrodynamics).

It is possible to estimate the likely migration direc-tions from source bed to reservoirs by mapping theorthocontours of the likely carrier systems (Figure 20).

Orthocontours are simply lines constructed on amap at right angles to the contours. Instead of dis-playing areas of equal height (or depth), they depictlines of maximum dip. The buoyancy effect dictatesthat the rising petroleum will follow such ortho-contours. Clearly, such an exercise must be at-tempted on the geometry of the carrier bed(s) as itwas during the phase of petroleum migration. Thisclearly leads to attempts to reconstruct the basin his-tory in terms of deposition, structuring, and sourcerock maturation.

The capillary effect controls how much of a carrierbed becomes petroleum saturated. Rarely are carrierbeds of a uniform grain size distribution. Thus, pet-roleum will tend to migrate along the coarsest, high-permeability pathways (Figure 21). These mayoccupy 10% or less of any particular formation.Open fractures have the same effect as coarse beds.Petroleum will exploit them. Temporarily open frac-ture systems are commonly invoked as the mechan-ism whereby migrating petroleum ‘jumps’ upward inthe stratigraphy of a particular basin.

The rate at which petroleum migrates can becalculated using Darcy’s law

q ¼ �ðk=mÞðdy=dzÞ

where q is the volume of flow rate (m3 m�2 s�1), k isthe permeability, m is the viscosity (Pa s�1), and dy/dzis the fluid potential gradient.

Typical permeability values are: sandstones,10�12–10�15 m2 (1 D to 1 mD); limestones, 10�14–10�17 m2 (10 mD to 10 mD).

From these data, it is possible to calculate that themigration rate for petroleum in sandstone will be1–1000 km per million years and, in limestone,0.01–10 km per million years.

Phase changes will occur in petroleum as a result ofits migration upwards to regions of lower pressureand temperature. This is most important for high-temperature, high-pressure condensates, but any oilwill exsolve some gas if the pressure in the formationdrops below the bubble point. The residual petroleumand generated gas are then likely to behave differentlywith respect to subsequent migration.

At low temperatures (<70�C), and in regions inwhich there is significant water flow, petroleummay be degraded by bacterial action or by waterwashing. The bacterial process follows a systematicloss of the n-alkanes, branched alkanes, isoprenoids,alkylcyclohexanes, and polycyclic alkanes. This pro-gressive destruction of the petroleum leads to in-creases in the pour point and viscosity of the oil anda lowering of the API (American Petroleum Institute)gravity.

Figure 20 Orthocontours – reconstructed subsalt petroleummigration pathways, Ewing Bank to Green Canyon areas, Gulf of Mexico, USA. Reproduced with permission fromMcBride

BC, Weimer P, and Rowan MG (1998) The effect of allochthonous salt on the petroleum systems of the Northern Green Canyon and Ewing Bank (Offshore Louisiana), Northern Gulf of

Mexico. American Association of Petroleum Geologists Bulletin 82: 1083–1112.

246

PE

TR

OLE

UM

GE

OLO

GY/O

vervie

w

Figure 21 Petroleum migration along high-permeability sand-

stone beds within a stacked sequence of turbidite sandstones and

siltstones. The migration route was exposed during the excav-

ation of a road cutting in Ecuador. Photograph by M. Heffernan.

Reproduced from England WA, Mackenzie A, Mann D, and

Quigley T (1987) The movement and entrapment of petroleum

fluids in the subsurface. J. Geol. Soc., vol. 144, p. 327. London.


Tertiary Migration

Tertiary migration includes leakage, seepage, dissipa-tion, and alteration of petroleum as it reaches theEarth’s surface. The products of seepage may begas chimneys in the shallow sediment, gas hydratelayers and mounds, cemented pock marks and mudvolcanoes, effects on vegetation, and live oil and gasseepage at the surface.

The physical processes that drive tertiary migrationare the same as those that operate during secondarymigration. Buoyancy drives the petroleum to the sur-face. This may be helped or hindered by overpressuregradients or hydrodynamics. The only major differ-ence that can be used to separate tertiary migrationfrom secondary migration is the rate of petroleumsupply. Trap failure, through capillary leakage, hy-draulic fracture, or tectonism, supplies petroleum

into a new carrier system much more rapidly thandoes a maturing source rock.

See Also

Petroleum Geology: The Petroleum System; Explor-

ation; Production. Sedimentary Environments: Depos-itional Systems and Facies; Carbonate Shorelines and

Shelves. Sedimentary Processes: Karst and Palaeo-

karst. Sedimentary Rocks: Chalk; Dolomites; Sand-

stones, Diagenesis and Porosity Evolution; Limestones.

Tectonics: Faults; Fractures (Including Joints).

Further Reading

Abbots IL (1991) United Kingdom Oil and Gas Fields, 25Years Commemorative Volume, Geological SocietyMemoir No. 14. London: Geological Society.

Allen PA and Allen JR (1990) Basin Analysis, Principles andApplications. Oxford: Blackwell Science.

Archer JS and Wall PG (1986) Petroleum Engineering,Principles and Practice. London: Graham & Trotman.

Bathurst RGC (1976) Carbonate Sediments and Their Dia-genesis, Developments in Sedimentology 12. Oxford:Elsevier.

Dickson JAD and Saller AH (1995) Identification of sub-aerial exposure surfaces and porosity preservation inPennsylvanian and Lower Permian shelf limestones, east-ern central Basin Platform, Texas. In: Budd DA, SallerAH, and Harris PM (eds.) Unconformities and Porosityin Carbonate Strata, American Association of PetroleumGeologists Memoir 63, pp. 239–258. Tulsa, OK: Ameri-can Association of Petroleum Geologists.

England WA and Fleet AJ (1991) Petroleum Migration,Special Publication 59. London: Geological Society.

Foster PT and Rattey PR (1993) The evolution of a frac-tured chalk reservoir: Machar Oilfield, UK North Sea. In:Parker JR (ed.) Petroleum Geology of Northwest Europe:Proceedings of the 4th Conference, pp. 1445–1452.London: Geological Society.

Glennie KW (1998) Petroleum Geology of the North Sea,Basic Concepts and Recent Advances, 4th edn. Oxford:Blackwell Science.

Gluyas JG and Hichens HM (2003) United Kingdom Oiland Gas Fields Commemorative Millennium Volume,Memoir 20. London: Geological Society.

Gluyas JG and Swarbrick RE (2003) Petroleum Geoscience.Oxford: Blackwell Science.

McBride BC, Weimer P, and Rowan MG (1998) The effectof allochthonous salt on the petroleum systems of theNorthern Green Canyon and Ewing Bank (Offshore Lou-isiana), Northern Gulf of Mexico. American Associationof Petroleum Geologists Bulletin 82: 1083–1112.

Reynolds AD (1994) Sequence stratigraphy and the dimen-sions of paralic sandstone bodies. In: Johnson SD (ed.)High Resolution Sequence Stratigraphy: Innovations andApplications, pp. 69–72. Liverpool: Liverpool University.

Selley RC (1996) Elements of Petroleum Geology, 2nd edn.San Diego: Academic Press.

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