1.3 Geological characteristics of hydrocarbon reservoirs · 2017. 3. 24. · 1.3.1 Reservoir rocks...

1.3.1 Reservoir rocks

Hydrocarbons accumulate below the Earth’s surface indeposits known as reservoirs. All accessible andcommercially viable reservoirs feature two essentialelements: reservoir rock and a hydrocarbon trap.

The reservoir rock, which is porous andpermeable, contains the hydrocarbons; determiningthe nature of this rock and its geometry is the goal ofhydrocarbon exploration. The boundaries of the rockmay coincide with the actual accumulation ofhydrocarbons, although the latter are usuallyconcentrated in a well-defined portion of a moreextensive formation. Reservoir rocks must have pores(empty spaces): the percentage of empty space in thetotal volume of the rock is known as porosity. Thepores must be communicating, and of a dimensionwhich allows the hydrocarbons to move around.Permeability is the measure of fluid’s capacity tomove around within the rock.

The hydrocarbon trap is a particular distribution ofrocks in the subsurface that keeps the hydrocarbonsinside the reservoir rock until they have been reachedby the drilling and can therefore be extracted. The topof the trap consists of impervious rock (sealing rock)which prevents the hydrocarbons, generally lighterthan the fluids they are mixed with, from migratingtowards the surface. The bottom limit of the reservoiris the generally flat and horizontal surface thatseparates it from the underlying fluid, normally saltwater, which accompanies hydrocarbons in theirmarine origin. Less commonly, when the water is inmotion, the separating surface may be inclined;depending on the type of hydrocarbons present, thissurface is called either oil-water contact or gas-watercontact, or more simply water level. The bottom of thereservoir is often also bounded by impervious rockwhich the hydrocarbons are unable to penetrate.

Aspects studied during exploration include thereservoir’s shape, size, gas and oil contents, and itsphysical parameters such as temperature, pressure andsolubility of the gas in the oil. The porosity andpermeability of the hydrocarbon-bearing rocks, theirvertical and lateral variations, and, finally, the amountof fluids to be extracted in the times deemed suitablefor full development of the reservoir, are also studied.

The reservoir’s size and shape depend on itssedimentary origin and, above all, on the sedimentaryenvironment in which it originated. Generally,reservoirs are not homogeneous: variations in therock’s characteristics are normally due to primarydepositional processes.

A reservoir’s sedimentary environment ischaracterized by physical, chemical and biologicalprocesses that are different from those of adjacentdepositional areas, and are the result of climate, floraand fauna, lithology, geomorphology, tectonic contextand, in marine environments, water depth,temperature, and chemism. In general, continental(subaerial) environments are more exposed to erosion,while marine environments are mostly depositionalareas.

Determining the environment in which the rockhas deposited is essential in reconstructing thereservoir’s geometry and other characteristics. Theenvironment determines the sediment facies, definedas the lithological (lithofacies) and biological(biofacies) characteristics of a stratigraphic unit,linked to the sedimentary process forming it. Afacies does not indicate an environment but one ormore processes through which the sediment wasdeposited (Mutti and Ricci Lucchi, 1972). In orderto define the sedimentation environment, it isessential to consider the association of various faciesor, in other words, how the facies are vertically andlaterally positioned.

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1.3

Geological characteristics of hydrocarbon reservoirs

Facies analysis takes into consideration thefollowing sedimentary aspects (Zimmerle, 1995): a)inorganic sedimentary structures such as cross-bedding, graded beds, sole marks, palaeocurrents, etc.;b) the presence of flora and fauna and their habitat,along with the organic sedimentary structures (fossilmoulds); c) granulometric distribution andsedimentary textures; d) mineralogical composition;e) geochemical composition (trace elements and stableisotopes); f ) stratigraphic relations (morphology of theenvironment, unconformities, magnetic polarity).

A sedimentary sequence shows the verticaldevelopment and environmental evolution over time,and can be studied using sequential stratigraphymethods. Lateral facies variations highlight theenvironment’s distribution in space according to theprinciple, expressed by Johannes Walther in 1894(Ricci Lucchi, 1978), that: “only facies that deposit incontiguous environments can overlie in sedimentarycontinuum”. This concept was successfully appliedalso to interpret the complex stratigraphic sequencesof the Alpine formations, where different overlyingand heteropic units can be identified.

Analysis of the sedimentary environment,indispensable in stratigraphical analyses applied to oilexploration, requires in-depth knowledge ofsedimentary processes and is based on the concept thatcurrent sedimentary environments provide the key tothe past; that is, we can interpret ancient environmentsby applying the principle of actualism. Along with thestudy of lithofacies and biofacies, performed in thefield through direct observation by field geologists,subsurface geologists exploring for oil may also carryout studies based on deep exploration (Ori et al., 1993).This involves the analysis of electrical properties(electrofacies) and radioactive characteristics obtainedfrom electrical and radioactive well logging, and fromseismic surveying (seismofacies).

Analysis of electrical and seismic diagrams mustnaturally be accompanied by observation of the sameformations in the field. However, the structuresinvolved in oil exploration are mostly buried and onlyin extremely favourable cases do they offercomparable outcrops. The two study methods (surfaceobservations and the study of electrical, radioactive,and seismic diagrams) are complementary becauseinterpretation of subsurface data allows for physicalanalysis of quantitative parameters that cannotnormally be applied to outcrops.

In particular, analysis of electrical and radioactivewell logs offers the following advantages, some ofwhich are obviously the result of three-dimensionalstudy that only a subsurface analysis can provide:• Absolute objectivity of data, being obtained

exclusively with the use of instruments.

• Possibility of evaluating, even on the basis of asingle test well, a stratigraphic sequence of somethousands of metres and, therefore, a picture of thesedimentary vertical evolution.

• A picture, through correlation of data obtainedfrom various wells, of the lateral variations ofindividual stratigraphic units; data correlationprovides a perfect view of the way in which singleformations or sequences of formations developeven over great distances.

• Precise stratimetric evaluation of formations,sequences, megasequences and, in general, of unitsof all ranges, bearing in mind that logs areregistered on various scales. Knowing the dip offormations allows corrections of thickness.

• Determination of important physical parameterssuch as porosity, permeability, and resistivity,which are of great importance when exploring foroil.

• Information about the fluids contained in thereservoir rock.

• Speed in using diagrams, if a full set of logs isavailable, when exploration is at an advanced stageor completed.The most important reservoir rocks are

sedimentary rocks of clastic origin and those ofchemical origin, especially carbonate rocks. Bothtypes, when subject to deformations, can fracture andgive rise to a third type of reservoir rock. In thedescription that follows, in accordance with adistinction that is commonly drawn in the literature onpetroleum, the sedimentary environments of clasticrocks and of rocks of chemical origin are dealt withseparately, even though some sedimentaryenvironments can give rise to both types of rock.

Clastic rock reservoirs

Most hydrocarbons accumulate in clastic rockswhich also contain most of the reserves in the largestknown reservoirs. Reservoirs are located mostly insands that have undergone varying degrees ofcementation; cemented sands are called sandstone.Less frequently, reservoirs may be found in deposits ofcoarser clastic rocks, such as gravel andconglomerates. The nature of the particles forming aclastic rock is prevalently siliceous, though clasticsediments of carbonate or, more rarely, gypsumcomposition are also widespread.

A typical characteristic of silicoclastic reservoirs isthe hydrocarbons’ migration velocity, from 1 to 1,000km per million years, decidedly greater than incarbonate rocks. Most reservoirs are contained instructural traps. Until 1970 it was believed that only10% of the reservoirs discovered were contained in

86 ENCYCLOPAEDIA OF HYDROCARBONS

GEOSCIENCES

stratigraphic traps, but as stratigraphic-sedimentological know-how improved, especially asregards the interpretation of sedimentationenvironments, the estimated percentage roseconsiderably.

We will describe the typical continental and marineenvironments of silicoclastic rock deposition (RicciLucchi, 1978; Reineck e Singh, 1980; Selley, 1988;Zimmerle, 1995), and set them in relation to theoriginating transport agent.

Reservoirs in fluvial deposits (alluvial environments)

These are contained either in braided or inmeander deposits, which result from the wandering ofriver beds. The former are coarser, especially at thelow end of the sedimentary sequence, and becomefiner towards the top, with truncations caused byerosion of successive, laterally-migrating channels. Inriver deposits with meandering morphology, sanddeposits have lateral accretion.

Fluvial deposits are often texturally immature,especially close to the source where they may beconnected with alluvial fans and therefore do not havehigh porosity levels. This is not the case, however, inchannel deposits that constitute the best reservoirs andalso have more favourable conditions for the formationof stratigraphic traps. Excellent reservoirs of this typeare to be found in the Nubian Cretaceous sandstonesthat extend from Algeria to Egypt, and are amplyexploited in Libya, and in the Muribeca sandstones ofBrazil, also Cretaceous.

Reservoirs in eolian deposits (desert environments)These consist primarily of medium or fine sands

that sedimented after being carried by the wind, anexogenous agent mainly acting in zones with a desertclimate, whether tropical (Sahara, Kalahari, Australiandeserts) or in the mid-latitudes (Gobi), as well as incoastal areas (Atacama, in northern Chile). Theyconsist of:• Hamada deposits, belonging to rocky terrain

characterized by large blocks or angular-edgedpebbles, often deposited directly on the basement.

• Serir deposits, with pebbles of various sizesirregularly scattered on sandy terrain as a result ofthe action of the wind that has removed the finerelements.

• Wind-carried dunes, which constitute classic sandseas. They are easily recognizable by the high-angle cross-bedding, and have good level ofporosity due to the absence of argillaceous matrixand the high degree of sorting (grains of the samesize). The vastness of these sediments can give riseto large reservoirs, often sealed by black shales

resulting from marine transgression, which providea good cap; in this case, stratigraphic trapsoriginate as a result of unconformity.

• Wadi deposits, named after the watercourses thatcross the deserts, and which flood during sporadicstorms; in these deposits the transport mechanismis fluvial.

• Löss deposits, originating from extremely finesands removed from desert areas, kept insuspension for long periods of time and depositedat great distances over vast areas.Reservoirs in desert environments are widespread

in Palaeozoic rocks, as in the Permian (Rothliegende)of the North Sea, in the Pennsylvanian of Wyoming(USA) and in the eolian sands of the North-AmericanJurassic (Navajo, Nugget Sandstone).

Reservoirs in lacustrine depositsThese are less widespread than the types described

above and are linked to deposition of turbiditesediments at the margins of lakes, especially in deltasand deeper areas, and therefore have marked turbiditedepositional characteristics. Reservoirs of this type arefound in Utah (Uinta Basin) and in China.

Reservoirs in delta depositsThese are typical of the transition between a

continental environment (delta plain) and a marineenvironment (delta front). In the delta plain, sedimentsare the same as those of the alluvial type in theirupstream portion, while in the downstream part theyare often influenced by tidal motion. Deltamorphology is often characterized by lobes ordigitations, each of which behaves like a single delta-like apparatus, with its system of channels separatedby fine interlobe deposits. The coarser sedimentsdeposit on the prograding part of the delta (Fig. 1)which, if affected by the destructive action of thewaves and tides, may assume a classical delta-typeconfiguration (e.g. the Nile). If the constructivedeposition action prevails, as along the coasts ofinland seas or gulfs where the erosive efficiency ofwaves is low, the body advances with marineregression and the formation of lobed (Po) or bird’sfoot (Mississippi) deltas. Lobes may be abandoned,with avulsion of the corresponding channel, while theriver builds a new one either to the side or above. Inthis way, sand deposits with a highly articulatedhorizontal and vertical distribution are created (16partly overlapping digitations have been counted in theMississippi delta). This can represent an idealcondition for the presence of reservoirs in sand orgravel deposits with the transition to finer prodeltadeposits. Caps are represented by successive marinetransgressions with clay deposits. Other reservoirs


GEOLOGICAL CHARACTERISTICS OF HYDROCARBON RESERVOIRS

may form, due to the instability of the prodelta,accompanied by landslides, slips and flow of detritalmaterial. Also syndepositional deformations, such asthe grow-faults common to the Gulf of Mexico,represent opportunities for the formation of traps. Adelta’s progradation is favoured by a lowering of thesea level, producing what is also known as ‘low stand’according to terminology based on studies ofsequential stratigraphy (Vail et al., 1977), whichdetermines an increase in volume with significantimplications for the interpretation of the sedimentationenvironment of hydrocarbon reservoirs.

These types of reservoirs are of considerablevolume, such as the Triassic ones of Prudhoe Bay inAlaska, the Jurassic ones in the North Sea, the Jurassic-Cretaceous ones of western Siberia, the Cretaceous onesin Kuwait and Saudi Arabia, and those in the presentdeltas of the Niger and Mississippi rivers.

Reservoirs in coastline and shallow-sea depositsThese are formed by the action of the waves and

tides, can extend for hundreds of kilometres

interrupted only by river mouths or tide channels, andcan be of a considerable thickness as a result ofvariations in the sea level (Fig. 2). Also in thisenvironment, the low stand favours the accumulationof sediments, while storm waves determine their shapeand granulometric variations.

Deposits with this origin are characterized bygood porosity but their volumes are not comparableto delta deposits. The largest are located in westernSiberia and in the central-Asiatic countries(Tajikistan), as well as in the North Sea, in UpperJurassic-Cretaceous rocks.

Reservoirs in deep-sea depositsThese consist of sediments with considerable lateral

and vertical extension that are largely the result of thesedimentation of turbidity currents generated throughthe action of subsea currents of clay and sand mud,which slide along the slopes of continental margins.The mechanism that gives rise to the turbidity currentdepends on the sediment’s angle of repose: when thatangle is exceeded as a result of the progressive


GEOSCIENCES

2

A B

C D

0

1

3

25

50

m

fluvial sand

major sand facies:

fine grain facies:

delta front:

channel mouth bars distal bar sheet sands andshoreface

tidal sand bars

delta plain prodelta and shelf tidal flats bird’s foot

Fig. 1. Deposition of deltaic sediments. A and C, deltas affected by the destructive action of waves or tides; B and D, constructive deltas with lobed or bird-foot deposits prograding into the sea; 1-2, electric logs; 3, lithological column of bar and deltaic-plain sand deposits. The broken lines indicate marine or swamp clays; sands are indicated by dotted lines (Magoon and Dow, 1994).

A B

C D

accumulation of material on the slope, the materialslides down, giving rise to a high-density current. Thecurrent is often triggered by a seismic shock and it isfor this reason that turbidity currents are typical oftectonically unstable basins, especially foredeep ones.

The motion occurs as a result of gravity since thematerial in suspension is denser than the surroundingwaters. The currents gain speed as they descend alongthe slope, then disperse and lose transport efficiency inthe open sea, giving rise through settling to thecorresponding clastic deposits known as turbidites.

The same depositional mechanism repeats itself,giving rise to a series of sedimentary bodies consistingof individual overlying turbidite bodies which formhundreds or thousands of layers. The sedimentarybodies settle at the bottom and, above all, at the baseof the continental slope, giving rise to a fan thatwidens with an ever-decreasing dip towards the opensea (Fig. 3), of a shape similar to that of deltas but withbroader geometry. The continuous superposition ofsedimentary bodies and their development towards theopen sea result in the progradation of the fan (Muttiand Ricci Lucchi, 1972). Within this, on the basis ofthe facies associations, it is possible to identify aninternal part towards the fan apex, comprising thechanneled bodies that contribute to the fan accretion,

along with an intermediate and an external part inwhich the turbidite beds have uniform and continuousdevelopment over great distances. The largest fans,such as the one in the Gulf of Bengal fed by the deltaof the Ganges, cover millions of square km.

Each turbidite event gives rise to a sedimentarysequence: the faster settling of coarse material(normally sand) determines a major concentration ofcoarser material at the lower part of the sequence;grain size decreases vertically and the finer, clay partis deposited in the upper portion (graded sequence). Aturbidite succession will therefore have hydrocarbonaccumulations concentrated in the coarser, porous-permeable portions of each sequence, while the finerportions may represent individual caps. Porosity isnever very high because of the presence of anargillaceous matrix in the sands, but volumes can beremarkable as a result of the extensions of the fans andthe presence of numerous superposed pools separatedby beds of clay.

When turbidity currents are deposited inrelatively restricted sections (foredeep basins), theyform deposits that are laterally confined andlongitudinally highly developed. In these contexts,the currents may cover an entire basin, no longergiving rise to fan-type progradation, but to a vertical



50'

alluvialsandstone,mudstone,

coal

progradingnearshore

marinesandstone

older deposits

lagoon

shoreface erosion

progradation

washover fan

marsh-lagoonalupper shoreface

lower shorefaceshoreface

offshore

beach-duneridges

beach-dunebeach sea level

resistivitySP

marine shaleand siltstone

marsh

marsh

lago

onbe

ach

fare

sho

re

lagoon beach transition zone

clay sand silty clay

shoreface

shelf

back

sho

re

dune

s

lago

on b

each

lagoonalpond

sand,silt sand, silt, claypeat

ebb tidal delta

flood tidaldelta offshore bar

barrier

Fig. 2. Shallow-sea sediments. A, electric log of shelf deposits moving upwards to coastal and alluvial ones following a regression; B, section representing the vertical and lateral distribution of regressive coastal-beach dune deposits; C, distribution of shallow-sea deposits (Magoon and Dow, 1994).

A

B

C


GEOSCIENCES

100 m

0

DIAGNOSTICAL TRAITS OF MAIN ASSOCIATIONS OF TURBIDITIC FACIES

indi

cativ

e sc

ale

A: shelf zone

A

B1: upper slope zone

B2: lower slope zone

C1: inner fan zone

B1

B2

C1

submarineplain

C2: middle fan zone

C3: outer fan zone

D: submarine plain

slump scars

slump accumulations

faciesA and B

faciesD

faciesF

pelitic inclusions

thickening-upward

thinning-upward

stratigraphic unconformitieslinked to slump scars

faciesC

inner fan

lower slope

upper slope

middle fan

outer fan

faciesE

faciesG

C: canyon

C2

C3

D

D

D

D

C

CC

Vm: main valleys

Vs: secondary valleys

Cp: peripheral channels

Abv: between valleys areas

Vm

Vs

Vs

Cp

Cp

Cp

Abv

Aiv

Abv

Fig. 3. Turbidite deposition environments: the reservoirs with the largest volumes occur in the channels of the lower slope, in the internal and intermediate fan and in the sands of the external fan. The latter, which have a great lateral extension,contains good reservoirs in foredeep basins, where the compression phases accompanying and following sedimentation createanticlinal structures with their corresponding traps (Mutti and Ricci Lucchi, 1972).

accretion of marked thickness. This is the case of theAdriatic Foredeep, the site of the largest gasreservoirs in the Mediterranean area. Other largeturbidite reservoirs have been discovered in the NorthSea, California, along the Brazilian continentalmargin etc., predominantly located in Tertiarydeposits which originated in the disintegration ofmountain chains.

Carbonate reservoirs

Carbonate rocks too, can contain largehydrocarbon reservoirs, especially those that haveundergone dolomitization, which determines a notableincrease in porosity and permeability.

The sedimentation environments of rocks ofchemical origin are mainly marine and the result ofevaporation processes, since decreases in the carbondioxide content of water favour the precipitation ofcalcium carbonate; the presence of organisms thathave fixed calcium carbonate in their shell gives riseto rocks of biochemical origin. The most favourablesedimentary environment for the precipitation ofcarbonates is the continental shelf and its reefs.

The internal shelf, connected to coastal deposits,includes tidal and sub-tidal environments resultingfrom the action of the tides, with sand bars and coastallagoons. Lateral variability causes a mosaic of sands(consisting of carbonate minerals if due to thedisintegration of reefs) and calcareous muds (algalplains with stromatolites). These formations can havemarked lateral development on shelves with low seabedgradients, or encircle islands, especially atolls. Theintermediate and external shelves host finer deposits(grainstones and mudstones; Bosellini, 1991) which,in zones subject to the effects of strong tides, arereworked by the marine currents.

In hot climates, the formation of reef mounds alsoknown as bioherms, with highly porous and permeabledeposits (a characteristic that becomes even morepronounced as a result of subsequent dolomitizationphenomena), is important in the formation ofreservoirs. The development of shelf and reef depositsis associated with marked subsidence phenomena(Fig. 4) and with the corresponding marinetransgressions that allow for the vertical grading of thesedimentation and its lateral progradation (highstandin sequence stratigraphy).

These deposits have highly variable facies, fromthe bioconstructed body of the reef to the back-reef,where shallow water aggrading calcareous formationswith algae and molluscs dominate, to the fore-reef,where waves break more intensely.

At present, the main reef-building organisms arealgae and corals, whereas in fossil reefs we find

stromatoporoidea and rudists. Many of theseorganisms have an inorganic calcite part, but some,such as Codiaceaen algae (for example, Halimeda)and numerous molluscs, also contain aragonite. Thedissolution of aragonite produces precipitation ofcalcite with low magnesium content, until the latterpartially dissolves, with a resulting increase inporosity. The thinnest, ramified corals are broken bythe waves, especially during storms, and form a highly porous coralligenous breccia all around the reef.

The morphology of these sediments can varygreatly: some reef systems run parallel to the coast,like the Australian Great Barrier Reef, others surroundislands (atolls) as in the Maldives, often encirclingvolcanic systems as is the case in Polynesia; in thesecontexts, the disintegration caused by storm wavesgenerates a broad ring around the island. Thisvariability influences the shape of deposits associatedwith back reefs, which in atolls cover their entireinternal circumference, and in volcanic islands takethe shape of a circular crown. The growth of reefs(Bosellini, 1991) in the external zone, where theyrepresent a barrier to the waves, can give rise to afringing reef that encircles the land, emerging from thewater when the shelf is narrow and the reef growsattached to the coast. If the shelf is relatively wide, thereef forming at the margin and separated from thecoast by water (lagoon) is referred to as a barrier reef.The tides create channels in the reef, which thus tendsto form numerous independent islands.

The vertical shape is determined by therelationship between the subsidence of the sea bed andthe vertical accretion caused by bioconstructingorganisms that find an optimal habitat a few metresbelow the surface. If subsidence is rapid, theorganisms must grow vertically to offset theprogressive deepening of the water; if it is slow, theorganisms develop slowly, allowing for theprogradation of the reef, while the sides are the seat ofdetrital sediments resulting from the partialdisintegration of the reef itself. If, finally, subsidenceeither slows down or comes to a halt, the organismstend to develop at their ideal depth, widening thebioconstruction until it assumes a mushroom-shapedappearance. Dolomite reefs, for example, can be ofnotable thickness, as is the case in the Ladinian andCarnian outcrops in the Trentino-Alto Adige region,which are around 1,000 m high.

The sediments of the carbonate shelf, which arealso often dolomitized, have a greater lateraldevelopment than that of reefs, and a similar thickness.In the eastern Dolomites, the ‘Dolomia Principale’(main dolomite) deposits outcrops extensively; the factthat the northern edge of the Gondwana



supercontinent, the site of Triassic carbonatesedimentation, developed uninterruptedly all the wayfrom Europe to northern India, gives us an idea of thesize of this shelf.

Shelf deposits develop vertically to compensatefor the effects of subsidence. The reservoirs arelarger than those in reefs and the cap can berepresented by the development of terrigenousshelves with a high percentage of clay, or bycompacted limestones.

Reservoirs in Devonian shelf and reef depositsare widespread in Alberta (Canada), with spectacularoutcrops in the Rocky Mountains. All of NorthAmerica is rich in carbonate reservoirs, in internal-shelf facies (tidal plains) and Ordovician to Permianreefs. Large reservoirs are also present in theJurassic calcareous sand bars of Saudi Arabia andCretaceous ones of Iraq. Carbonate reservoirs fromthe Tertiary are to be found in the Persian Gulf andin California.


GEOSCIENCES

back-reef lagoon

reefdetritus

reef slope ponding basin

detriticalbrecciasof taluspl

ain

fron

t

iperhalitic deposits

Carlsbad Group

Capitan Limestone Bell Canyon0 1 2 3 km

Carlsbad facies:dolomites

Capitan reef facies:dolomites and limestones

Delaware facies:gray sandstones

800

400

0

progradation

coast lagoon

reef complex

back-reef

inne

r sl

ope

reef

s.s

.

oute

r sl

ope

tran

siti

on

fore-reef

basin

basin deepening upward aggradation

m

Fig. 4. A, reef complex with its associated depositional systems; B, stratigraphic evolution of the Ladinian shelves in the Dolomites in a subsidence regime; C, stratigraphic section of the Permian Reef Complex in Texas-New Mexico (Bosellini, 1991).

A

B

C

Fractured-rock reservoirs

Almost all rocks, including sedimentary ones, withthe exception of evaporites, are fragile enough tofracture during deformational processes. The forceneeded to fracture rock is much greater in acompressed regime than in an extension one; thereforefractured-rock reservoirs are usually present in thelatter context. The fracturing of a rock body does notnecessarily imply a regionally extensional regime andcan also take place in a localized extent.

Fracturing takes place in compact rocks. Insandstones, fracturing normally affects the cement, asit is rare for fractures to cross granules except in thecase of siliceous cemented rocks such as quartzites,which are, however, poor reservoirs. In carbonaterocks, fractures develop throughout the entiresedimentary body. Porosity and permeability are bothstrongly affected, but above all the latter, since themigration of fluids tends to concentrate along thefracture surfaces.

In originally impervious rocks such as highly-cemented or matrix rich clastic formations andcompact limestone, fractures determine secondaryporosity and, above all, effective permeability. In acontext characterized by frequent and openfracturing, the latter parameter may be practicallyinfinite. In carbonate rocks, moreover, fractures canbe migration channels for solutions that are rich incarbon dioxide and therefore have strong dissolvingeffects which tend to widen open fracturesconsiderably.

The effects of fracturing, on the other hand, dependon the depth at which the phenomenon takes place.Indeed, below a certain depth - depending on tectonicstress, the type of rock and type and quantity of fluid -fractures do not remain open, and are cemented againby chemical precipitation from solutions flowingunderground. When the phenomenon precedeshydrocarbon migration, a new deformation stage isrequired to re-establish a network of fractures: if thecement can be dated, it is possible to reconstruct thedeformational history of the reservoir rock.

Causes of fracturingThe areas where this phenomenon is most

frequently observed are those close to major faults,followed by those close to zones where folding occursand, finally, by those in regions characterized byhomoclinal dip. The most common causes offracturing are the following (North, 1985):• Forces that run parallel to bedding (buckle folding),

which mostly affect massive rocks or ones withthick bedding and little tendency towards plasticity.Fracturing is facilitated by the presence of a plastic

substratum and is concentrated along the crests ofanticlines, which are subject to local tension.

• Forces orthogonal to bedding (bending folding),resulting from an extension that gives rise todifferential subsidence and the consequentformation of horst and graben structures. Thefractures propagate upwards at the sides of eachblock and also affect the folded part that drapes thefaults.

• Extension faults with associated fracturing thatincreases logarithmically as it approaches the faultsurface (these can be formed also in a regime ofcompression when faults and folds areinterconnected).

• Pressure of fluids, associated with a solution(pressure solution) in carbonates. In acompressional regime, discontinuities (stylolites),together with microfractures (tension gashes) thatrun perpendicular to them, are formed.

• Differential lithostatic pressure due to uplift anderosion.Other factors that cause fracturing are dehydration,

washouts (especially in erosion surfaces that underlieunconformities), and the cooling of igneous rocks thatmay serve as a reservoir.

Examples of reservoirs in fractured rocksThe best-known and studied example of a reservoir

in fractured carbonates is located in the Iranian AsmariLimestone (Oligo-Miocene). The reservoir, situated inlimestone structures more than 300 m thick, wasdeformed in a wide-radius fold with a net of laterallyand vertically connected fractures that favour a highrate of production. Mexico owes its oil productionmainly to reservoirs in fractured Mesozoic limestone(Tamaulipas Limestone): the fracturing is of thesecond generation type and took place during foldingthat occurred as a result of the structures being raisedduring the Tertiary. In Venezuela (Maracaibo Basin),the reservoir is situated in cretaceous limestonestructures, in anticlines that were formed between theCretaceous and the Miocene. Permeability has beenamplified by the flow of solutions along the fractures,some of which were later reduced as a result of theprecipitation of calcite. Other examples are to befound in the Cambro-Ordovician of Texas, the Permo-Triassic of China, and in the Mississippian of westernCanada, at the foot of the Rocky Mountains.

Large reservoirs situated in fractured siliceousrocks are found in diatomite deposits in California (theMonterey Formation of the Miocene). Oil is alsoproduced by the dolomite interbedded with diatomite,and by the fractured rocks of the basement.

Fractured black shales also make excellentreservoirs, such as the Devonian in the Appalachians;



the shales there are the source rock, the reservoir rock,and the cap rock, but production requires artificialfracturing on a vast scale.

Examples of deposits in fractured sandstonereservoirs are found in the Oriskany Sandstone, one ofthe first reservoirs to be exploited in the Appalachians.A more important reservoir is located in Texas (theSpraberry Formation of the Lower Permian); there,however, the fractures function more as flow channelsthan as reservoirs.

Igneous rocks and basement rocks, if they areintensely fractured, can also be exploitable reservoirs,as is the case in Argentina (Mendoza Basin, in Triassictuffs), in Arizona (fractured syenite veins of theParadox Basin), and in Russia (metamorphic rocks ofthe Hercynian basement in the Don depression).

Physical parameters of a reservoir rock

Various physical parameters characterize areservoir. In addition to porosity and permeability (seebelow), also temperature, pressure, density, and thephase that characterizes individual fluids, i.e. gaseous,liquid, or solid, come into play. The above-mentionedfactors interact with one another: for example, achange in temperature or pressure can determine achange of phase. Reservoir rocks are usually full ofwater at the time of deposition and, subsequently, aftertheir migration, the hydrocarbons fill up the pores andreplace the water.

Temperature varies directly with depth. Thegeothermic gradient (on average, 1°C every 30 m ofdepth) is influenced by geographic location and otherlocal factors such as the possible presence of volcanicactivity or the flow of underground waters. Referencetemperatures are often obtained during drilling orproduction, and they are largely influenced by thoseoperations. In these conditions, the temperature of thesediment and of the fluid it contains are not inequilibrium, and the measured gradient is lower thanthe real one.

The minimum pressure of a reservoir is thehydrostatic one or, in other words, that of the watercolumn, which is equal to 1 atm for every 10 m ofdepth. That value is hardly ever reached in practice asa result of the presence of the lithostatic (or geostatic)load of the superposed sediments, which influencesthe bottomhole pressures and always produces highergradient values, usually of about 1.5 atm and, inexceptional cases, up to 2 atm.

Another important physical characteristic ofreservoirs is gas saturation. The oil in the subsurfacealways contains a certain percentage of dissolved gas, andthis percentage may be greater than the amount of gassoluble in oil at the existing temperature and pressure.

In this case, the force of gravity causes the gas toconcentrate towards the summit (gas cap). If thepercentage of dissolved gas is lower, the gas remains insolution until a decrease in pressure, resulting from theexploitation process, frees a certain amount of it, whichthen accompanies the oil that has been produced or fillsthe spaces in the reservoir that have been evacuated bythe extracted oil and gas. The overpressure thatcharacterizes gas cap hydrocarbons facilitates theextraction of oil which rises towards the surface as aresult of the push effect when the gas expands (gas drive).

PorosityPorosity is determined by the ensemble of empty

spaces (i.e. the volumes that are filled with fluid)present in the reservoir rock, which are normallyrepresented by the rock’s own pores, but also by emptyspaces, interstices or fractures, that intersect the rock.Porosity is measured in terms of the ratio of the volumeof the empty spaces to the total volume of the rock. Inpractice, in order for a reservoir to be producible,porosity must normally be greater than 5%, but at greatdepths with accompanying high pressures it is possibleto work even at lower porosity levels.

A distinction is made between total porosity andeffective porosity: the former is defined above, even ifit must be taken into consideration that many pores in areservoir may not be interconnected, that hydrocarbonswill therefore be unable to migrate through them, andthat others are partly reduced because the rockfragments that surround them contain interstitial waterthat cannot be displaced. This is the case of clays thathave overall porosities of more than 50% but which areto a great extent filled with interstitial water. Effective(or efficient) porosity is therefore represented by thevolume of the pores in which the fluid is alsoeffectively able to flow. Pumice, for example, whichhas a total porosity of more than 50%, has no effectiveporosity; the pores it contains are not interconnectedand fluids are therefore unable to infiltrate andpenetrate it. This is why it floats on water.

Porosity can vary considerably inside a reservoirrock, both vertically and laterally, as a function ofvariations in the nature of the rock itself. Porosity is infact influenced by the sedimentation environment bothin space (lateral variation) and over time (verticalvariation). Porosity can be primary, when formedduring the deposition of the sedimentary rock, orsecondary, when formed in the wake of processes thathave affected the subsequent transformations ordeformations of the rock itself.

Primary porosityThis is characteristic of clastic rocks; fragments

deposited by settling leave open spaces that are


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sometimes filled with particles of smaller dimensions,often of a clayey nature (the matrix). The spaces thatremain empty constitute the porosity, which isinfluenced by the sediment texture. The parametres ofsediment texture are: size and shape of the fragments;their arrangement in space; diagenesis, essentially inthe form of compaction, both during and afterdeposition, and in the form of cementation.

The dimensions of the fragments play an importantrole regarding porosity, not so much as a function oftheir size as of their granulometric distribution. In fact,if they are of similar size, porosity may be quite high;in this case, we speak in terms of a well-sortedsediment. If the sizes of the particles differconsiderably, the opposite occurs; the smaller-sizedfragments fill up the spaces left open by the larger-sized ones and, as a result, the porosity diminishes(poorly-sorted sediment).

Oil companies quantify the degree of sorting bycarrying out laboratory analyses on the distribution ofthe fragment sizes (granulometry). A clasticsediment’s granulometry is represented graphically bya diagram showing the dimensional classes of thegrains in a logarithmic scale on the x-coordinate, andtheir percentages on the y-coordinate. In the graph, awell-sorted sediment will show a characteristic ‘acute’maximum, corresponding to the most highlyrepresented class (also known as mode) of fragments.In this case, porosity will be high. However, if thegraph is flat, and all classes are uniformly represented,

the sediment is poorly sorted (highly assortedgranulometrically), and porosity is limited.

Finer sediments normally have higher porositiesbecause they consist of grains of similar sizes, even ifthe latter are often not interconnected. For example,clays will contain spaces occupied by interstitial water,which cannot be removed under static conditions, andif they have not been compacted they can reachporosities of around 50-80%. Sands, too, offer gooddegrees of porosity (20-40% if they are not cemented),whereas coarser clastic rocks (conglomerates, gravels,etc.) have statistically lower porosities since the sizesof their elements are highly heterogeneous and thesmaller clasts fill up the spaces between the larger-sized ones.

Porosity is also affected by the fragment shape: thehighest degrees of porosity are reached with fragmentswith an almost spherical shape (or a high coefficient ofsphericity), which are found in sediments that haveundergone a long rolling process during transport. Thespatial arrangement of grains also affects the degree ofporosity: a cubic distribution (joining the centre ofeach sphere, a cube is obtained) can reach 47.6%, anorthorhomboidal one 39.5%, and a rhombohedral one26.0% (Fig. 5). These are always theoretical maximumsthat can be reached with uncemented spherical grainsof equal size. In practice, the grain distribution variesover time as a result of the lithostatic load that causesthe grains to compact more, and the porosity todecrease.

The highest porosities (which can theoreticallyreach a level of just less than 48%) thereforecorrespond to loose fragments that are of equal size,spherical, and with a cubic spatial distribution.

The sedimentation environment affects primaryporosity. The most porous clastic rocks are the sandsof desert and beach origin, which are highly sorted,especially if they have been affected by the wind.Sands from terrigenous shelves or deltaic sands, beingaffected by the presence of a clay matrix, are fairlyporous. Turbidites are far less porous, since their masstransport in subsea environments does not separate thesand from the clay. Compaction, cementation and, ingeneral, all diagenetic processes are important factorsthat have a negative effect on the degree of porosity.

Diagenesis determines a change in themineralogical composition, and is of great interest tothe petroleum geologist since it modifies porosity,permeability, entry pressure, and saturation inirreducible water. Deep-set sandstone deposits aresubject to pressure as a result of the lithostatic load,and therefore experience a decrease in porosity. Thiscondition may reverse locally below theunconformities, where dismantling and washout canlead to dissolution, especially in carbonate cements,



case 1

case 2

case 3

Fig. 5. Three types ofspatial disposition of spherical grains ofequal size with theirrespective empty spaces(North, 1985).

with a resulting increase in porosity and permeability.Furthermore, carbonate cements can dissolve duringsubsequent burial, as a result of the presence of carbondioxide, while the decarboxylation of organic matter inadjacent source rock is underway (Taylor, 1977).

The lithostatic load due to the weight of sedimentswhich deposit over time on top of the reservoir rockfavours its compaction, affecting clastic rocks inparticular. Sands and coarse sediments are only slightlyaffected by this phenomenon (2% reduction in porosityper 1,000 m load of sediment): this factor can have anappreciable effect only after very long periods of time.

Clays, however, can be reduced in volume by asmuch as 50%; their behaviour whilst subject to load isvery different from that of sands, first of all because ofthe high water content that accompanies theirsedimentation. This is the case of clay mud, in whichsolid particles represent less than half of the totalvolume. During the compaction process, water issqueezed out of the pores, which then progressivelydiminish in volume. Clay minerals are phyllosilicates,with a planar reticulate, and they do not assume aparallel arrangement in the mud. Moreover, theseminerals contain reticular water that must be added tothe water present in the pores. During compaction, thewater is expelled, the mineral reticulates change,become smaller, and align themselves with anorientation in parallel planes. Furthermore, the pores,

especially the larger ones, lose much of their volume.The sediment’s density progressively increases fromvalues of just more than 1 kg/dm3, typical of mud, to alevel of about 2 kg/dm3: a clayey sedimentarysequence may therefore be reduced to a thickness thatis close to half of its original one. Compacted clays arebest defined as shales. Deformations tend to reduceporosity even further; for example, as of result of therock’s plasticity, a fold in shale beds will have limbsthat are thinner and therefore less porous than the zoneof its crest.

A considerable lithostatic load, accompanied byhigh temperatures, can transform clays into slates orphyllites. These are true metamorphic rocks; they haveno porosity and their density is the same as clayminerals, i.e. up to 2.6-2.7 kg/ dm3. In foredeepsedimentation, consistent sedimentary accumulationsof turbidite, resulting from the disintegration ofmountain chains, deposit on top of clay sedimentsoften interbedded with sands. Here, the geostatic loadmay reach many thousands of metres of thickness andcause the sediments to sink. Lithostatic load increaseswith depth, and so does temperature, which becomesyet another factor contributing to compaction. A highgeothermic gradient favours compaction at greatdepths and will produce an accentuated diminution inporosity (Fig. 6).

Carbonate rocks, too, are subject to compactionprocesses. At first, the carbonate sedimentation givesrise, in a basin-type environment, to a water-richcalcareous sludge. The percentage of water is less insediments that are rich in organisms, especially inreefs, which are a largely bioconstructed type of rock.Compaction determines a pressure solution thataccompanies the diagenesis of carbonate rocks, withthe formation of particular irregular seams known asstylolites.

Cementation, too, has the effect of reducing porosityin clastic rocks. Immediately after its deposition throughsettling, the sediment is crossed by circulating solutionsthat precipitate substances which either partially ortotally occlude the pores, lithifying the sediment andtransforming it into a compact rock: sand, for example,will thus be turned into sandstone. The cement can bemade of calcite, silica, or, more rarely, gypsum. Itscomposition will depend on the nature of the grains ofthe rock: a quartz and feldspar-based sand (arkose) willusually be cemented by silica (silicon arenite), acalcareous sand by calcite (calcarenite). Solutions,however, especially those that contain solublecomponents which are widespread in rocks such ascalcium carbonate, may originate from adjacent rocks,so that sandstone with quartz and feldspar-based grainsthat are cemented by calcite is also quite common.Many minerals can play the part of cement, but only a


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0 10 20 30 40

0

1

2

3

porosity (%)

26° C/km

35° C/km

dept

h (k

m)

Fig. 6. Relations between porosity and depth as a function of two different thermal gradients(measurements carried out in sandstones of the Pacific Northeastern Arc) (North, 1985).

small number of them exist in sufficient quantities to beof interest to petroleum geologists. These include quartzand the carbonates calcite, dolomite, to a lesser extentsiderite, and, under particular circumstances, anhydrite,barite, fluorite, halite, iron oxides, and pyrite, all ofwhich make up common cement. Secondary feldsparoften accompanies secondary quartz. Clay mineralssuch as kaolinite, illite, chlorite and smectite grow asauthigenic compounds. The cementation processgenerally concerns only permeable rocks; that is, onesthrough which these solutions are able to flow. Inimpervious rocks such as clays, only compaction, andnot cementation, processes are observed.

Carbonate rocks present a primary porosity whenthey undergo a clastic-type sedimentation process(clastic carbonate rocks). Primary porosity may alsobe due to the instability of some minerals that haveprecipitated or have been fixed by calcareousorganisms. Aragonite, for example, is an unstableelement that soon turns into calcite with highmagnesium content. Because of their high solubility incarbon-dioxide-rich water, limestones that have justbeen deposited are often immediately dissolved bymeteoric water, with a resulting increase in porositythat, since it is almost simultaneous withsedimentation, can still be defined as primary.Deposited grains differ from those of the silicoclasticrocks due to their greater roughness and irregularity.The polyconcave pores are larger in grainstones suchas calcarenites, especially if they have deposited inback reefs. In ooliths, in which the elements have asubspherical shape, high porosities are evidenced.Reduced porosities are characteristic of packstones,wackestones and mudstones, and their porosity isfurther decreased during diagenesis. Even with only afew hundred metres of load, compaction reduces thevolume by 25-30%, and thus decreases the porosity,especially if the carbonate is still in a dissolved,uncemented state. Cementation in carbonate rockoccurs through precipitation of spar-calcite fromdissolved carbonate originating from the limestonedue to pressure solution.

Secondary porosityThis is the result either of chemical processes,

which can dissolve soluble fragments or cement andgenerate empty spaces, or of physical ones, resultingfrom deformations that crush the lithified rock whichis no longer capable of being deformed plastically, andthereby produce fractures. In clastic rocks, secondaryporosity develops as a result of the circulation ofsolutions with a high carbon dioxide content andconsequent high dissolving power; for example, somesandstone is cemented with calcite, which is partiallydissolved, generating empty spaces.

Secondary porosity resulting from chemicalprocesses, however, is characteristic of carbonate rocks.The dissolving process that takes place alongpreferential paths, such as fractures for example, tendsto make the fractures wider and thus favour the increasein porosity and permeability. The end result is the onsetof a karstic morphology. These events are favoured byphases of regression that expose the limestones to theaction of meteoric water, which is rich in carbondioxide; subsequent transgression invades the washed-out and dissolved zones, creating an unconformitywhich, if characterized by the deposition of imperviousrocks, can provide an excellent cap for a possibleporous and permeable reservoir.

The most important chemical process isdolomitization; i.e. chemical transformation caused bycalcium/magnesium exchange (metasomatism) withrecrystallization of the rock. Many of the largestcarbonate rock reservoirs are located in dolomitic rockreservoirs. This phenomenon is observable in 80% ofNorth-American Palaeozoic hydrocarbon reserves,where the process has had more time to take place andbeen favoured also by the presence of organisms withshells, which are more suited to transformation.However, the phenomenon can be witnessed only in20% of the reserves in the Persian Gulf, wherecarbonate reservoirs are made up of more recentformations.

The process takes place after sedimentation ofcarbonate, at any stage of diagenesis and overconsiderably long periods of time: the possibility ofsynthesizing dolomite at low temperatures has notbeen verified in the laboratory, so the existence ofprimary dolomites is doubtful. Current carbonatescomprise metastable minerals such as aragonite andMg-calcite, whereas ancient carbonate rocks are madeup of calcite and dolomite. It is possible to distinguishearly dolomitization, as observed in tidalenvironments, from a late metasomatic one that erasesthe rock’s original textures and produces crystallinedolomites which are usually rather coarse, with largeautomorphic crystals and saccharoidal textures(Bosellini, 1991).

The conversion of aragonite and Mg-calcite intocalcite is a mineralogical stabilization process thatinvolves the reduction of only a small quantity ofmagnesium. The conversion of calcite and aragoniteinto dolomite, on the other hand, requires afundamental chemical and mineralogicaltransformation. The replacement of calcite withdolomite entails an increase in porosity of around12%. Since the dolomitization process may be onlypartial, the increase in porosity will only take place inpart of the carbonate rock, and it is in that part thatmost of the hydrocarbons will be stored.



Dolomitization occurs in various phases: in theinitial phase, rhomboids of linear dimensions rangingfrom 20 to 100 mm are formed, of the same size ineach layer. After this, the spaces between therhomboids are created, with the formation of asaccharoidal texture. In addition to absolute porosity,effective porosity is also increased in the process,since rhombohedrons of dolomite are characterized byplanar surfaces. Moreover, a dolomite reservoir ismore resistant to compaction compared to a limestoneone, and the highest porosities among carbonate rocksare therefore found in dolomites.

Dolomitization is particularly intense in reeflimestone and especially in back-reef environments,where there is more evaporation. These limestones arebioconstructed and the process is therefore favouredby the abundance and nature of fossils.Dolomitization affects fossils selectively, insofar asaragonite, which forms a part of corals and ofgasteropods and cephalopods, has a crystal lattice thatis volumetrically similar to dolomite and, therefore,the process is faster in these fossils. More time isrequired for the transformation of calcite with a highcontent of magnesium derived from the shells ofbrachiopods (organisms that are very widespread inPalaeozoic reefs), and also of echinoderms, bryozoa,pelecypods (including rudists, the organisms thatbioconstructed the Cretaceous) and ostracods.

As regards plants, calcareous algae undergo a rapiddolomitization process since some are aragonitic andothers are formed from calcite with a high magnesiumcontent. Furthermore, they themselves reduce thesulphate that slows down the process. The highfrequency of Palaeozoic dolomites, therefore, is due tothe development of algae in that era.

The great volume of the sediments involved indolomitization (in the region of the Dolomites, theirthickness is greater than 1,000 m and they coverextremely vast areas) requires a mechanism anddriving force which maintain enormous quantities ofdolomitizing fluid in motion over long periods oftime. Various circulation systems capable oftransporting the necessary magnesium have beenhypothesized (Bosellini, 1991).

Porosity measurementsQuantitative evaluations of porosity levels

performed in the laboratory on field and core samplesare carried out using an instrument designed ad hoc,the porosimeter. This measures the total rock volume,i.e. that of the liquid displaced by immersing thesample, whose external surface has been previouslysealed with a plastic material, and the total volume ofthe pores (the volume of liquid required to completelysaturate the sample). Porosity can also be measured

using subsurface methods, above all by means of asonic log and radioactive well logging (neutron logand formation density).

Porosity levels (in percentage) may thus beclassified as follows: a) 0-5, minimum, typical of well-cemented sandstones and compacted limestone; b) 5-10,poor, in partially-cemented sandstones and calcarenites,scarcely fractured or fissured limestones; c) 10-15 fair,in poorly-cemented sandstones, conglomerates, highlyfractured and fissured detritic limestone, dolomites; d) 15-20, good, in deposits of sands with a low level ofcohesion, gravel, fractured dolomites; e) above 20,excellent, in loose and well-sorted sand and vuggy,highly fractured and fissured dolomites.

PermeabilityThis is the property that allows fluids to pass through

rock without moving its constituent particles or causingstructural modifications. Whereas porosity affectshydrocarbons under static conditions, permeability is adynamic function which enables rocks to release fluidsand not only to contain them. Fluids pass through a rockby filtration through pores (permeability by porosity) orby direct transmission through discontinuities(permeability by fracturing or fissuring).

Permeability is quantified by determining theamount of fluid that passes through a rock surfaceunder stable, differential pressure conditions. In orderfor a fluid, and in particular for an oil or gas, to crossor flow through a rock, there must be a difference(gradient) in pressure. Over very long periods all rockswill present a certain degree of permeability, but inpractice a reservoir’s commercial potential depends onthere being a significant level of permeability in verybrief periods of time.

Darcy’s law (1856) links the velocity of thefiltering fluid to permeability according to theequation: q�(k/m)�(dp/dx), where q is the velocity ofthe fluid (in cm/s), k is the permeability in darcys, m isthe viscosity (dynamic) in centipoises and dp/dx is thedifference in pressure (p) in the direction of flow (x) orpressure gradient. Viscosity expresses the fluid’sinternal resistance; i.e., the resistance encountered bythe fluid’s particles moving at different rates. Onceviscosity is known, the rock’s permeability can bemeasured. The practical unit of measurement ofpermeability is the darcy (equivalent to 9.87�10�13 SIunits). According to the definition of the API(American Petroleum Institute), a darcy is thepermeability of a porous medium in which a singlefluid phase with a viscosity of 1 centipoise, whichentirely fills up the medium’s empty spaces, flowsthrough the medium under laminar regime conditionsat a flow rate of 1 cm/s per cm2 of cross-sectional area,under a pressure of 1 atmosphere per cm. Since the


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darcy is too large a unit to be used in practice,the petroleum industry tends to express permeabilityin millidarcys.

Absolute permeabilityAbsolute permeability does not depend on the

nature of the fluid but entirely on the rock’scharacteristics. It can be calculated as k�Nl2 where Nis a dimensionless number (constant for each rock)that sums up the rock’s characteristics, such as itsshape and the arrangement of its fragments, and l isthe length of the pore structure. The relevant factorsare thus pore size and the tortuosity of the fluid’s path– in other words, the size, sorting and compaction ofthe clasts (North, 1985).

Darcy’s law is based on the assumption that onlyone fluid is present in the rock. When the reservoircontains gas, oil and water, absolute permeabilityvalues are less indicative; in fact, the fluids interferewith each other and effective permeability must becalculated for each fluid in the presence of the others.

Relative permeabilityRelative permeability is the ratio between effective

permeability at a given fluid saturation, and absolutepermeability at 100% saturation of that specific fluid;saturation means the volume of fluid expressed as afraction of the total volume of the pores. In practice,relative permeability levels are calculated until therock is 100% saturated with a single fluid.

Most reservoirs contained water before themigration of hydrocarbons. When hydrocarbonspenetrate they occupy the larger pores and force thewater into the smaller ones, where it is already presentas a result of capillarity. Oil mixed with water may beextracted during the production stage.

When saturation in hydrocarbons increases, therelative permeability to water gradually decreases andmay reach zero values when the saturation in water isaround 45%, depending on the nature of the reservoirrock and the fluids’ physical properties. The reservoirmay then produce hydrocarbons that are water-freebecause the hydrocarbons have displaced all of thewater except the amount withheld by way of capillarityin pores that are too small for the hydrocarbons topenetrate (irreducible saturation in water which canreach values of up to 30% in fine-grained rocks). Ifboth oil and gas are present, production will depend onthe percentages of the two different hydrocarbons:mixed production can occur, or only gas may beproduced when permeability to oil is zero as a result ofthe high level of gas saturation.

Statistically, high porosities correspond to highlevels of permeability: a theoretical relation existsbetween the two parametres but, at a given porosity,

permeability can vary greatly as it decreases with theroughness of the fragments and the length (tortuosity)of the path. Clearly, it will also depend on poregeometry and size. The relation therefore depends onthe nature of the rock. Clays, for example, especially ifthey are poorly consolidated, are very porous butentirely impervious because the pores are very smalland often filled with interstitial water throughcapillarity, preventing the passage of fluids; in fact,they are excellent rock caps. Gravels are highlypermeable; the fluid’s path follows large-radius curves(reduced tortuosity), although they are less porous thansands as a result of their low degree of sorting, andtherefore the smaller grains fill the spaces between thepebbles. As a result, a sand reservoir will usuallycontain more hydrocarbons than a gravel one of thesame size, even though the former is less permeable.

In rocks of chemical origin, high porosities may beassociated with high levels of permeability. This occursespecially in carbonate rocks when both parameters area result of fracturing, fissuring, recrystallization ordissolution, and assume unidirectional characteristics.Dolomites are particularly hard but brittle, whensubject to deformations, so dislocations cause them toshatter and to crumble; higher levels of permeabilityare measured in these cases, often exceeding 1,000millidarcys.

Permeability measurementsAbsolute permeability can be measured in the

laboratory using a permeameter. This instrumentconsists of a cylindrical core-sample holder, a pumpthat forces fluid through the core sample, pressuregauges upstream and downstream of the sample tomeasure the drop in pressure, and a flow meter tomeasure the rate of flow of the fluid in the core sample.Measurements are standardized so that statisticallycomparable data can be obtained: core samples arecylindrical, of a diameter of 2 cm and a length of 3 cm.

Relative permeability measurements, usuallyreferring to two fluids, require more complex apparatusin which the sample is exposed to the flow of the twofluids in varying percentages. Permeability is calculatedon surface samples but more often on subsurface coresamples, from which the rock plugs to be tested areextracted. In order to calculate effective permeabilitylevels under reservoir conditions, formation tests haveto be carried out by analyzing pressure buildup curves,i.e. the pressure trend over time from the moment inwhich production is interrupted.

Certain peculiarities of permeability must beconsidered when preparing core samples for the test:in fact, a horizontal (or lateral) permeability exists dueto the fluid’s motion along the bedding plane. This iscalculated by testing core samples collected parallel to



the bedding plane. Vertical permeability, across thebedding planes, is usually smaller, and is affected bythe beds’ planar arrangement and lithologicaldiscontinuities along the vertical axis. This holds truefor vertical wells that cross horizontal formations,otherwise the relative dips have to be evaluated.

High vertical permeability can occur in dislocatedbeds: a fault can be a surface with greater permeabilitydue to the rock’s fracturing, especially in the case ofhard rocks such as cemented limestone and sandstone.In other cases, when the fault fracture is filled withsoluble cement (such as carbonate rock and calcite-cemented sandstone reservoirs), dissolution planes thatfavour permeability may be present along its surface.In non-vertical but dipping faults or fractures, thepresence of discontinuities is a decisive factor for highpermeability values (directional permeability),because it is along these surfaces that movement takesplace, and not through the pores. Fissure-relatedpermeability, especially through fractures that havewidened as a result of dissolution, can be hundreds oftimes greater than porosity-related permeability.

The permeability of rocks, expressed inmillidarcys, is classified as follows: a) up to 15, weak;b) 15-50, moderate; c) 50-250, good; d ) 250-1,000,very good; e) above 1,000, excellent.

It is impossible to evaluate rock types belonging tothe various categories because permeability isdependent on fractures and fissures. According to dataobtained from 1,000 tests, 80% of all sedimentaryrocks have practically zero permeability (up to 10�3

md); for example clays or shales, which are the mostcommon cap rocks, followed by evaporites. 13% ofsedimentary rocks have permeability values of up to 1md, 5% from 1 to 1,000 md, while only 2% haveexcellent permeability.

Main reservoirs

As described above, reservoir rock is generallyformed of porous and permeable sedimentary rock.The main reservoirs are thus contained either in clasticrocks, principally sands or sandstones, or in rocks ofchemical origin, usually carbonate rocks such aslimestones and dolomites. Many deposits containreservoirs of both clastic and carbonate rocksinterbedded in vertical stratigraphic succession.

More than 60% of the world’s oil reserves arelocated in the Middle East, above all in Saudi Arabia,the country with the greatest oil reserves, while Russiahas the greatest gas reserves.

An overview of the world’s main reservoirs bygeographical area (North, 1985; Barnaba, 1998) isgiven below, along with a brief description of thosecalled supergiants (containing more than 5 billion

barrels of oil; that is more than 700 million tonnes ormore than 850 billion cubic metres of gas), and giants(between 500 million and 5 billion barrels or between85 and 850 billion cubic metres of gas).

EuropeIn Europe, the largest reservoirs are located in the

North Sea and Russia. In the North Sea andNetherlands offshore, oil and gas are produced fromPermian to Palaeocene reservoir rocks. Gröningen, inthe north of the Netherlands, is the largest Europeangas field; the reservoir rock is Permian Rothliegende(upper red sandstones) and the cap is Zechstein withfrequent saline rocks. In the North Sea, the Brent andPiper oil reservoirs are in Jurassic sands, while the oilat Ekofisk is in Cretaceous-Palaeocene (Danian)limestones capped with Tertiary clays. In the Forties,reservoir oil is contained in Palaeocene sands.

In European Russia, the largest reservoirs arelocated in the belt from the Urals to the Caspian Sea(Volga Basin). The reservoir rocks are mostlyPalaeozoic and consist of arenaceous deltaic Devonianrocks (oil) and fractured dolomitic Permian limestones(gas). In the Ukraine, reservoirs are located in rocksfrom the Devonian to the Permian, in Romania, in thePliocene sandstones of the Moreni-Guna Ocnitei fieldin the Carpatian Basin.

In Italy, gas reservoirs are found in clastic rocks ofthe Tertiary Apennine foredeep (Mattavelli andNovelli, 1988), from the Po river valley to the Adriaticoffshore, to the Bradano Trough (Casnedi, 1991). Oilreservoirs are found in Mesozoic carbonate rocks(Milano and Novara Provinces, the Adriatic offshore,Basilicata and Sicily).

Smaller reservoirs, which are nonetheless importantdue to the industrial context in which they are located,can be found in Carboniferous sandstones in northernGreat Britain, and in the Permian Zechstein formationsin southern Great Britain, northern France andGermany. There is another oil field in Germany, in theHanover Basin, in Mesozoic sandstone.

Other small reservoirs are located in the Rhinetrench and in the Anglo-Parisian basin. Many Jurassicand Cretaceous formations take their name fromlocations of this basin. There are also further reservoirssurrounding the Pyrenees; the French ones are in theAquitaine Basin, in Triassic and Jurassic limestone anddolomites with evaporites (Lacq gas field), and aremore limited on the Spanish side. The most importantSpanish reservoirs are in the Tarragona Basin, inJurassic dolomitic limestones.

AsiaThe world’s largest reserves are in the Middle East

(Iran, Iraq, Saudi Arabia, and other countries of the


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Arabian Peninsula). The stratigraphic succession hasmany productive levels, from the Ordovician to theTertiary, in various groups of formations: the KhuffGroup, where the reservoir rock is Permian dolomiticlimestone and Permian and Lower Triassic sandstone;the Arab-Zone Group, with Upper Jurassic limestoneand dolomite reservoirs; the Cretaceous Group, withlimestone, sandstone and sand reservoirs; and theAsmari Group, whose reservoir rock is very permeableas a result of the fracturing and fissuring of Oligo-Miocene detritic and organogenic limestone, intowhich hydrocarbons migrated from Cretaceous rocks.

Other important Asiatic reservoirs are located inSiberia, mainly in Upper Jurassic to Cenomanian sands,mostly containing gas. From western Siberia to theBarents Sea offshore, oil and gas reservoirs are locatedin Permian-Triassic clastic rocks. Very ancientreservoirs (Proterozoic and Lower Cambrian clasticrocks and carbonates) are located between the Lena andTunguska rivers, and other giant hydrocarbon depositshave recently been discovered in Kazakhstan, north ofthe Caspian, in Palaeozoic carbonate reservoirs.

Further large reservoirs worthy of mention are theChinese ones in Tarim (Xinjiang-Uigur), in LowerPalaeozoic limestones and dolomites, carboniferouslimestones and Miocene deltaic sands. There are otherproductive basins in eastern China and Manchuriawhere continental sediments prevail.

AfricaThe sedimentary basins in and around Africa have

excellent hydrocarbon potential. In the AlgerianSahara there is the Hassi Messaoud field with aCambrian sandstone reservoir and other smallerOrdovician to Lower Carboniferous sandstonereservoirs. Cretaceous-Eocene sandstone andorganogenic limestone reservoirs have been discoveredin the Sidra Basin in Libya, and in Tunisia there is theel-Borma field (oil) in Lower Triassic sandstones. InEgypt, there are reservoirs in the Nile delta (gas) andin the western Red Sea-Sinai Peninsula (oil). TheNiger delta basin in central Africa, Nigeria and theGulf of Biafra contains large reservoirs. The oilformations there (Akata, Agbada and Benin) areTertiary deltaic sands. Other important reservoirs arelocated in Gabon, Congo and Angola.

North AmericaNorth America has enormous oil-producing

potential and is the continent that has been mostcarefully studied in geological terms, with reservoirsdiscovered back in the Nineteenth century. In thenorth, Alaska has large reservoirs but climaticconditions make exploration and development verycostly. The Prudhoe Bay field in the Arctic Sea,

probably the largest in the North American continent,has various pay levels, the deepest of which is thePermian-Triassic limestone. In the same area oil isalso found in Cretaceous rocks, while gas-bearinglevels are found in Tertiary reservoirs.

In western Canada (Alberta) there are largereservoirs in the Devonian limestone reefs that outcropextensively throughout the Rocky Mountains. On theeastern side of the Rockies, between Edmonton andCalgary, limestone deposits are capped by imperviousevaporite formations. The extension of the Devonianreefs in that area was favoured by palaeoclimaticfactors: indeed, in that period the area was crossed bythe equator. The Upper Palaeozoic carbonates ofnorthern Alberta contain significant heavy oilreservoirs. In the same area there is also a giantdeposit of Cretaceous bituminous oil sands (tar sands).

In the Appalachian Basin there are reservoirswhich were discovered back in 1859 (Edwin Drakedrilled the first well, with the geological and chemicalconsultancy of Benjamin Silliman, in westernPennsylvania). Many are Palaeozoic levels: from theOrdovician carbonate rocks to the Silurian sandstones,and the shallow sea Devonian clastic rocks coveredwith black clays, rich in organic matter, whichconstitute the source rock and also reservoirs throughfracturing. There are also the shallow-sea sandstonedeposits, and shelf and reef limestone and dolomitesformed during the Carboniferous and Permian. Thesehave good production levels, especially of gas.

West of the Rocky Mountains, in California, thelargest reservoirs are in the Cretaceous to Quaternarysandstones of the Los Angeles, Ventura, San Joaquinand Sacramento basins. The largest reservoir isWilmington, in Upper Miocene and Upper Pliocenesands deformed into a wide anticline. A vast oil-bearing region extends from east of the RockyMountains to the Gulf of Mexico (the Mid-Continent).Many reservoirs are located there, especially in theUpper Palaeozoic carbonate rocks and sands. Thereservoirs in Texas and Louisiana, which are oftenrelated to saline structures, are lithologically highlydiversified (mainly sands), and are located in rocksdating from the Cretaceous to the Tertiary.

Another important oil-bearing region is the GulfCoast, in Texas and Louisiana, with one third of theentire production of the United States. Sedimentationstarts in the Triassic (the area emerged during thePalaeozoic) with evaporites, followed by a thicksequence of clastic and carbonate rocks in a basin witha high rate of subsidence: the reservoirs are located intraps formed by faults cutting a Cretaceous-Miocenehomocline south-dipping with numerous salt domes.

In Mexico, the most productive area is the south-east of the country, on the coast of the Gulf of



Mexico, with reservoirs in Upper Jurassic fractureddolomitic limestones, in reef and shelf facies, and incalcareous sands that deposited on the sides of thestructures.

South AmericaIn South America the largest reservoirs are in

Venezuela, mainly in Cretaceous, and above all,Eocene to Miocene sands; the most important of theseare in the eastern part of the Gulf of Maracaibo. Ineastern Venezuela, to the north of the Orinoco, there isa vast outcropping belt (30,000 km2) with anenormous volume of Cretaceous to Eocene andOligocene bituminous sands (Orinoco oil or tar belt).The relatively low viscosity, poor compaction of thesands, high geothermic gradient and warm climateallow traditional steam injection wells to be used.

Other important reservoirs are located inColombia, Ecuador, Peru, Chile, and above all inBrazil and Argentina. In Brazil, the Reconcavo Basinreservoirs (which extend to the Baia de Todos osSantos near Salvador in the offshore Atlantic) arelocated in Jurassic to Cretaceous sediments; inArgentina, the Comodoro Rivadavia field is located inJurassic to Palaeocene sand lenses.

AustraliaAustralia has small reservoirs in the Cambrian-

Ordovician fractured sandstones of the Amadeus Basin(central Australia) and in the Devonian rocks of theCanning Basin (western Australia).

1.3.2 Cap rocks

These are impervious rocks that prevent the upwardmigration of the hydrocarbons. Since oil and gas arelighter than water, they tend to rise through the

reservoir rock until they reach an impervious barrierthat blocks their vertical migration (Fig. 7). Thisimpervious rock is usually concave in shape ifobserved from below and so it also prevents lateralmigration of the hydrocarbons, thereby constitutingthe reservoir rock cap.

Oil geologists often prefer to call the cap rock roofrock, using the term cap rock only for impervious rockthat seals salt domes. Another widely-used term is sealrock. If bedding favours the hydrocarbons’ lateralmovement, the cap rock can represent a lateral barrierto their migration (wall rock).

Characteristics of cap rocks

There is no such thing as a perfectly impervioussedimentary rock, but if a rock’s permeability is lessthan 10�4 darcys then it may be assumed to be aneffective cap; by nature it must be compact or havepores that are either not interconnected or too small toallow the passage of fluids. The efficiency of a caprock, measured by the width of the column of oil orgas that it can seal, is a function of its integrity (lackof open fractures), its continuity, thickness and the sizeof its pores. Another decisive factor for a cap rock’sefficiency is its pressure gradient: extremely highgradients can affect the rock’s seal.

The quality of a cap is affected by the physicalstate of the hydrocarbons: if they are in liquid state,the cap efficiency is greater; if they are in gaseousstate, and the cap in question is only slightly porous-permeable, with pores filled with water, the gas will beable to gradually displace the water and spreadthrough the cap. In this case, even if the cap is verythick, the gas will be able to cross it over long periodsof time. Caps able to maintain their integrity over timecan provide a reservoir with an effective seal forhundreds of millions of years.


GEOSCIENCES

porous beds impervious beds hydrocarbon reservoirs fault

Fig. 7. Various typologies of deposits with impervious cap rocks and reservoirs in porousrocks (Source: Eni).

If a rock is saturated with water, its capacity toprevent the passage of hydrocarbons within a giventime-frame depends on the minimum amount ofpressure required to remove the connate water from theseal’s pores or microfractures, thus enabling filtration.This pressure, known as capillary entry pressure, is afunction of the water-hydrocarbon interfacial tension(oil and gas have different interfacial tension), inverselyproportional to the maximum radius of theinterconnected pores, and able to confine thehydrocarbons within the reservoir. The hydrocarbons’upward drive, which is due to their low density, isquantifiable as the height of the hydrocarbon-bearingcolumn by the difference in density between them andwater (Downey, 1994). This drive must becounterbalanced by the capillary pressure of the caprock; otherwise, when the drive is greater than thecapillary pressure, the hydrocarbons will cross the rock.These parametres can also be measured in thelaboratory but it is difficult to extrapolate the behaviourof an entire cap rock and its reservoir from a sample.

The cap rocks that offer the best seal againsthydrocarbon migration have vast lateral continuity, arelithologically uniform, have a good level of ductility,and represent a significant part of a basin’s filling.

Ductility is the property of rock that favoursplasticity to deformations, and which increases withthe organic content (kerogen), pressure andtemperature. Clays and evaporites are the most ductilerocks and react to stress by deforming plasticallywithout fracturing. Arenaceous and carbonate rocks,on the other hand, are harder and, when subject todeformation, they are more likely to shatter, creatingopen spaces into which the hydrocarbons can migrate.

Lithology of cap rocks

The most common cap rock is clay, which sealsover half of the clastic rock reservoirs, whether it isinterbedded with them (as in the case of sand orsandstone and clay interbeddings that form turbiditesequence), or represents the end of a sedimentarycycle due to the deepening of a basin. Clay beds,which are common in turbidite sequences as a result oftheir continuity and lateral uniformity over greatdistances, provide excellent caps that lie on top of oneanother in innumerable layers. Moreover, turbiditesequences are usually deposited in a geodynamiccontext that favours the accumulation of very thicksediments (several thousands of metres). This thickaccumulation results in the compaction of the rock(especially clay), which renders it entirely impervious.Marl (clay with variable quantities of calciumcarbonate) behaves in a similar way to clay and cantherefore also represent a good cap rock.

Evaporites are ideal cap rocks. Halite, gypsum oranhydrite usually come at the end of an evaporiticcycle, often formed at the base by carbonate rockswhich can be good hydrocarbon reservoirs with animpervious and plastic evaporite cap. In the Permian-Triassic, evaporite sequences with carbonatesedimentary successions that have been sealed byevaporites are common and form innumerable gianthydrocarbon reservoirs.

A one-metre-thick bed of cap rock is sufficient toseal a reservoir hundreds of metres thick. For example,a clay whose pores are less than one-tenth of amillimetre in size can have a theoretical capillary entrypressure that can seal an oil column of 1,000 m. It isunlikely, however, that such a thin bed would becharacterized by sufficient lateral continuity withoutlithological variations or fractures to allow it to act asa cap for an economically exploitable reservoir.

Lateral permeability variations are fairly commonin clastic rocks; for example, a sand bed can becomelaterally more clayey to the point of losing itspermeability characteristics. If the bed is inclined, thehydrocarbons migrate through the sand until they areblocked by the increased percentage of clay, whichtherefore forms a permeability barrier. The same effectcan be seen as a result of a lateral increase in thecementation of a sandstone bed, with a consequentdecrease in permeability.

In exceptional circumstances permafrost can act asa cap rock, as seen in the Siberian taiga, where thegas-bearing reservoir rock is Cretaceous sandstone.

Cap rocks can form as a result of diageneticprocesses that render a previously permeable rockimpervious, such as: cementation throughprecipitation of salts dissolved from carbonate,siliceous or evaporitic rocks; recrystallisation;compaction due to lithostatic load; and redistributionof ductile minerals. The degradation of oil can result inthe formation of asphalt or impermeable tar, and in thereservoir rock being saturated with insoluble products:if these are concentrated at the top of the reservoir,they can act as caps.

Opposite processes can cause an impervious rockto lose its efficiency as a cap. The most common isfracturing as a result of dislocations, butdolomitization can render a compact limestone cappermeable and enable hydrocarbons to leak through it.

In addition to the common vertical type of cap, ortop seal, there are also lateral seals that preventhydrocarbons from migrating laterally and which arealso considered cap rocks. These phenomena are theresult of facies variations, from a porous-permeablerock to an impervious rock with greater capillarypressure or differential diagenesis. Lateral sealsformed by the displacement of rocks from different



environments, such as those deposited in animpervious rock after an erosion cycle, are also verycommon. In these cases, the shape of the seal plays animportant role; there is always a vertical component toevery migration process that the cap rock must seal.

Identification of cap rocks

Reservoir rocks sealed by potential cap rocks can beidentified through regional studies aimed at pinpointingthe areas where impervious cap rocks overlie porous-permeable formations. Lithofacies cartography isessential in these studies: lithofacies, porosity andpermeability properties must be established for eachstratigraphic unit. The superposition in stratigraphicorder of the maps obtained will identify the areas wherean impervious unit overlies a porous-permeable one, anindispensable requirement for the presence ofreservoirs. More detailed maps of the regionaldistribution and stratigraphic-structural characteristicsof cap rocks, along with identification of underlyingsource rocks, are used to interpret an oil system. Fieldstudies carried out with the aim of identifying seepagesmay also allow identification of the possible lack orpoor quality of a cap.

Regional study of an area’s potential starts with astratigraphic study to determine: the presence anddistribution of source rock; the existence and spatialconfiguration of the cap rock; favourable conditionsfor the presence of traps above or close to the sourcerocks. Of course, hydrocarbons can migrate across arock which was believed to be a cap and encounteranother cap above it.

Deformation of cap rocks

Most structural traps are the result of folds orfaults that cause deformations in the cap rock which, ifductile, will react plastically to the tension and deformwithout fracturing or creating spaces that would allowthe hydrocarbons to leak through them.

Anticline deformations can affect a sequence inwhich porous-permeable rocks alternate withimpervious ones which provide a series of caps,forming reservoirs in vertical succession. If animpervious level is not an effective cap, there may bean effective one at a higher level.

A fault-induced dislocation can be an excellent trapif the uplifted wall forms an effective seal. Forexample, if the dislocation of dipping formationsdisplaces a permeable sand bed under an imperviousclay, the latter will act as a cap rock. In other cases afault surface may represent a slight discontinuity wherethe capillary properties, nature of the fluids and bed dipallow the hydrocarbons to filter through and migrate

towards the surface. In this case the fault behaves likean open fracture. When the fault crops out, thehydrocarbons are dispersed in the atmosphere; themajority of surface shows are found along thesefracture lines. The effects of migration over timeshould not be underestimated, as permeability alongthe fault surface can annul the sealing capacity of theadjacent rock. The origin of the fault is usually decisivewhen evaluating its effect on the cap: a tensional(normal) fault will produce an open fracture far morereadily than a compressional (reverse or thrust) fault.

A fault’s effects on lateral hydrocarbon migrationmust also be taken into account. A fault rarely impedesmigration when it brings two porous-permeableformations into contact; for example, it cannot act as aseal between two displaced beds of sand on either limbof the fault. Exceptions to this rule may arise when avery plastic rock (clay, evaporite), sometimes set inmotion by high temperatures, has infiltrated along thefault plane and sealed it, and when the relative motionof the two limbs of the fault induces diagenetic orrecrystallisation phenomena, blocking the rock poresalong the fault plane.

To sum up, study of the petrophysical nature, arealdistribution and stratigraphic-structural configurationof the cap rock is essential for the identification of ahydrocarbon reservoir. Evaluation of individual caps isoften far more complex than that of the regional cap,especially in zones affected by fault systems, andrequires detailed analysis, supplemented withcartographic representations and cross-section plansproduced with the aid of seismic surveys to obtain athree-dimensional picture of the cap.

1.3.3 Hydrocarbon traps

As stated above, the essential factors for the presenceof hydrocarbons are a porous and permeable reservoirrock and a trap in which they can accumulate. This isdefined as the geometric configuration of the rocks inthe subsurface able to preserve their accumulation. Inbrief, any subsurface structure able to receivehydrocarbons and preserve them over time, until theyare extracted, can be called a trap.

The presence of hydrocarbons, althoughfundamental for the development of reservoirs ineconomic terms, is not taken into consideration in thedescription of the various types of traps. In otherwords, traps may contain potential reservoirs, butcertain elements, primarily the source rock in whichthe hydrocarbons must form in order to migrate intothe trap, may be missing. As a result, theaccumulation of hydrocarbons will not take place. Ageological structure can, therefore, be a trap even if it


GEOSCIENCES

does not contain hydrocarbons (Magoon and Dow,1994).

The main goal of oil exploration, therefore, is toidentify traps in the subsurface. The term ‘trap’ wascoined in 1934 by R.A. McCollough, who extendedthe concept of anticline used until then to a variety ofgeological conditions in the subsurface favourable forthe accumulation of hydrocarbons. The anticlinaltheory originated from a statistic which indicated thathydrocarbons accumulated along the axes of anticlinesin culminations. In this context, White (1885)published the anticlinal rule according to which“hydrocarbons move upwards as long as an anticlinalstructural deformation does not block their ascent”. Asexploration technologies advanced, reservoirs werediscovered in areas not necessarily linked to thepresence of anticlines. The more general concept of a‘hydrocarbon trap’, which can refer to situations thatare not only structural but also stratigraphic, wasintroduced: hydrocarbons move upwards as long as a

tectonic or sedimentary event does not prevent theirmovement and cause them to accumulate.

Traps are classified on the basis of theircharacteristics, although some traps are very particularand do not fit into any particular scheme. Someauthors consider the trap’s geometry, some themechanism that led to its formation, and others thenature of the reservoir and cap rock. The simplestclassification, accepted by the majority of authors, isthe one proposed by Levorsen (1956), which dividestraps into three types: structural, stratigraphic, andmixed, the latter being a combination of the firsttwo types.

Structural traps

These are the result of deformations occurring atthe same time or, more often, after the reservoir rockdeposited (Fig. 8) and are the easiest to identifybecause in some cases they are visible on the ground,



wrench fault

BCBC

BC

BCBC

BCBC

BC

A T

arches, domes

extensional block compressive block

thrust-fold belt

detached normal fault salt

Fig. 8. The most commontypes of structural traps. A, dislocation towards the viewer; T, dislocation in the direction opposite to that of the viewer; BC, basement (North, 1985).

when the structure crops out (Fig. 9). Even if they areburied, they can be identified using geophysicalmethods (Fig. 10). They were thus the first to beexploited.

Structural traps are the result of folds, faults, acombination of the two (as is often the case), orregional dipping of bedding. However, when they aresealed by an unconformity, it is considered preferableto classify them as stratigraphic traps, even ifdeformations occurring after the unconformity canmake their classification ambiguous.

In a structural trap there is a top and spill point.The top is the trap’s highest point, i.e. the point of the

reservoir to be reached at the minimum depth. Thespill point is the highest point from whichhydrocarbons can escape from the trap. The trapclosure is the space between the top and spill point(Fig. 11): if the entire interval is hydrocarbon-bearingit is called pay, otherwise the term is used to refer onlyto hydrocarbon-bearing stratigraphic intervals.

Traps caused by foldingAlthough generally used to indicate the result of

tectonic deformation, the term fold is purely ageometric description and refers to a curving ornon-planar arrangement of geological surfaces,


GEOSCIENCES

Yasuj

N 0 80 km

Abadan

IRAN

Kazerun

Lurestan

Khuzestan

Yasuj

Bushehr

Ahvaz

Bibi Hakimeh

Gachsaran

oil field

Kazeru

nQ

ata

rL

ine

Z A G R O S F O O T H I L L Souter simply folded oilf ie ld belt

inner simply folded bel t

MOUNTAIN FRONT

i mb r i c a t e d b e l t

t h r u s t b e l t

P E R S I A N G U L F

Fig. 9. On the right, an outcropping anticline on the Zagros mountains in Iran: the porous-permeable limestone deposits of the Asmari Formation are visible along its hinge, at the axial culmination, and on the sides, the impervious evaporites of the Gachsaran Formation, with their badland morphology. On the map above, the oil reservoirs of the Asmari Formation, in the hills facing the Zagros mountains, are indicated in black (McQuillan, 1985).

usually beds. The genesis of a fold need not bedeformation, and it may be sindepositional, as is thecase of folds due to differential compaction or thosedue to slumping.

The most common and important traps caused byfolding are convex traps, which often imply the foldingof a thick stratigraphic sequence usually characterizedby various overlying reservoir rocks. Convex traps,which vary in nature, geometry and genesis (althoughthe typical convex trap is an anticline, many fault trapsand salt domes also belong to this category), containmost of the hydrocarbon reservoirs.

Under static conditions, oil occupies the upperpart of the reservoir, unless the quantity of gasexceeds the amount required to saturate the oil atreservoir temperature and pressure; in this case, theexcess gas rises to the top of the reservoir and forms

a gas cap, with the oil below it. The structure may befilled with hydrocarbons up to its spill point: belowthat point, identified by the first open isobath onstructural maps, the oil and gas spill out sidewaystowards an adjacent structure. If the quantity ofhydrocarbons present in the reservoir is not sufficientto reach the spill point, water (usually salt water)collects beneath them.

The forces that can cause a reservoir rock to foldare widely discussed in geology and may be summedup as the result of tangential compressions acting onplastic rocks. Faults are created when their plasticitylimit is exceeded; in the majority of reservoirs, foldsare associated with faults.

Exploitation is easiest when the anticlinerepresents the deformation of a continuousstratigraphic series. It may contain various overlying



TW

T (

s)

G5

G4

G3G2

G1

Casnedi_f10

Middle Late Pliocene

Top of Miocene sequence

Top of Miocenesequence

Quaternary

Top of Miocenesequence

Early Pliocene

Early Pliocene

Liguridi unit

outcrops

EarlyPliocene

Agip-Varignana 1T. D. 2,637 m projected 2.5 km SE

0.0

1.0

2.0

3.0

4.0

Agip-Budrio 1T. D. 3,185 m

Agip-Selva 2T. D. 1,801 m

Fig. 10. Anticlinal traps faulted in a compressive regime, identified using seismic methods (Agip division in the Po River Plain) (Ricci Lucchi, 1986).

spillpoint

closure

water

oil

gas

Oil-WaterContact(OWC)

Gas-OilContact(GOC)

Fig. 11. Reservoir with closure and spillpoint (Source: Eni).

reservoirs, with their impermeable caps. Drilling cancross the reservoirs one after the other and make themall economically exploitable.

When an anticline extends to the surface, thestructure can be identified above ground level: if thereare reservoirs in the subsurface, the hydrocarbons areproduced from wells positioned along the axis of theanticline. In the area north of the Persian Gulf, forexample, outcrops of the deformed stratigraphicsequence have led to the identification of severalpotential hydrocarbon reservoirs, along with theirthickness, lithological characteristics, porosity andpermeability levels, and presence of cap rocks. In mostcases, however, the structure can not be identified onthe surface because it is covered by other discordantsequences or alluvial deposits: it is therefore referredto as a buried structure and can be identified usinggeophysical methods.

The axial culminations or depressions of ananticline can be identified by analyzing its geometry,the best area to explore being the zone of axialculmination, where the reservoir expands, increasingin volume (Fig. 12). When a culmination is particularlyextensive and raised, it is called a structural domewhose bedding does not dip symmetrically to thelimbs of the anticline but radially from the top; in thiscase development wells will be positionedconcentrically.

Of course, there are many types of convex trapsand the shape, width and general morphology of thefold may change with depth. In these cases, theinterpretation of the results of the preliminarygeophysical study must be reviewed in the light of dataobtained during exploration drilling. Convex traps canbe classified on a genetic basis:• Tangential compression, which can take place

without the basement necessarily being affected(buckle and thrust fold traps). These traps are saidto be ‘suspended’ because they end or are cut off atthe bottom.

• Vertical movements, which do not necessarilyimply a shortening of the crust (bending foldtraps), and usually involve the basement.

• Traps whose convexity is the result of geologicalevents preceding the overlying sequence.Convexity may result from the covering of aresidual relief (buried hills) or an existingsedimentary body (principally a reef). In bothcases, the beds cover the reliefs, draping over themon account of their convexity (drape folding), andthinning gradually towards the top.It is important to determine an anticline’s axial

plane: if the plane is vertical, wells remain alignedalong the axial plane even at a depth. Overlyingreservoirs, on the other hand, will be reached by wellsat increasing depths, but always at their culmination,


GEOSCIENCES

A B

A�

A�A B�

B

B�

�800 m

Srm2

Srm1

Krg

Srm2

Srm3

Srm1

Srm1

Krg

Krg Krg

Tsch

Tsch

TschTsch

Mkp

Mkp Mkp

�600 m

�400

�200

sea level

top of the series

seriesseries

series

the

wateroil

surface emergence of the line of upthrust

�1,000 m

7,820 m

"

"

""

""

""

subsurface projection of the line of upthrust

Fig. 12. Traps in a faulted anticline, illustrated with a structural map (A) and sections (B, C). Grozny reservoir, Chechen (Russia). The abbreviations refer to the formations crossed (Levorsen, 1956).

A

B C

and exploitation will therefore be easier and morecost-effective.

If the axial plane is inclined, drilling will reach theculmination at points that shift gradually in thedirection of the axial plane’s dip (Fig. 13). In this case,development is less economical since a greater numberof vertical wells, or directional wells parallel to theaxial surface, will be required to reach the pools.

The anticline may be asymmetrical: in this case, thereservoir rock will be more developed towards the lesserdipping of the fold’s two limbs. If there is convergence,i.e. a thinning of the beds in one direction, the positionof the structural high may vary considerably, and thevolume of the reservoir rock can change accordingly.

The radius of the fold may also change vertically, asis the case when a deformation tends to progressivelyreduce in intensity over time. The fold will therefore bemore pronounced in the older beds, which as a resultmay contain reservoirs that are thicker but aereallysmaller than the younger ones.

Overturned folds, with an axial surface close tohorizontal (recumbent folds), are often peculiarstructures. The reservoir may be located either in thefold’s upper portion or underneath, in the overturnedpart of the fold itself. In the second case, the reservoirwill be part of a succession of overturned beds which,in turn, may be located at the structural high (false

anticline). This type of trap is only rarely exploitablebecause the presence of intense dislocations makesstructural interpretation more difficult.

Drag folds, caused by friction in the brittle layersduring folding or by the slip of allocthonous units, areknown as minor folds, and influence the formation oftraps to a lesser extent.

The most spectacular example of anticlinal traps isthe folded structure situated in Iranian and Iraqiterritory close to the Zagros mountains (see againFig. 9); the 300-metre-thick Asmari Limestone(Oligo-Miocene) has been deformed in folds with awavelength of between 10 and 20 km, and anamplitude of 2 to 5 km. The overlying sedimentscontain evaporites that have reacted plastically tocompression and have slid down the anticline crests.

Other traps of great importance in oil explorationare salt domes, traps whose structural genesis isconnected to particular stratigraphic conditions, andare therefore normally classified as mixed traps (seebelow).

Homoclinal dips are common and economicallyexploitable structures. They may correspond to a foldlimb, even if its dip is slight. The trap is formed whenporous-permeable beds in the homoclinal successionare sealed in their upraised side either by faults (seebelow) or by sharp decreases in porosity orpermeability (permeability barrier). The latter casemay occur also when the beds crop out: the formationof asphalt or bitumen in their outcropping portion cancreate an impervious plug that prevents thehydrocarbons from migrating upwards and dispersingin the air. The transformation occurs as a result ofoxidation of the oil, which is favoured by the presenceof surface water. This type of trap may be classified asstratigraphic or mixed.

Understanding a reservoir’s geometry and, inparticular, the configuration of its top part is offundamental importance for its exploitation. Thisconfiguration is commonly represented on maps byisobaths that indicate the depth of the reservoir top,often with the highest point marked with the � plussign (structural or contour map). In an anticline, thecurves are subparallel and are spaced out inculmination zones, whereas they tend to be concentricin the case of domes.

The structural closure is the vertical distancebetween the highest point of the hydrocarbon-bearingfold and the structure’s deepest isobath; in this contextgas, oil and water are bedded, and hydrocarbons canpartially or totally occupy the interval above the lowestclosure contour line. If the surfaces separating gas, oil,and water, known also as gas-oil contact and oil-watercontact (either gas or oil may be missing) arehorizontal as in many reservoirs, they are graphically



400 m

200

m0

NW SE

400

600

800

1,000B

A

D

E

C1,200

1,400

0

Fig. 13. Anticline in Adriatic foredeep rocks(Cellino field, Abruzzo), with numerousreservoirs superposed in the hinge. Since the axis is not vertical, the reservoirs are out of alignment, with structural highs in the direction of dip of the axial plain(Casnedi et al., 1977).

represented as isobaths enclosing the productive area.The producing wells are placed within this area.

Traps caused by faultingThese are common, but statistics show that they

tend to create smaller reservoirs than those generatedby folds, with which they are often associated, alongwith other structural modifications such ashomoclines, bending of beds or stratigraphicvariations. Traps due to faults are formed when aporous-permeable level is displaced below animpermeable one, which acts as a seal.

In certain cases, the fault crops out: when it isassociated with hydrocarbon reservoirs, and does notact as a seal because the fracture is open, surface oilshows or gas leakages may be observable on theground. In order for a trap to be formed, the fault planemust be impervious. This happens in evaporiteformations if they contain porous levels, and in clasticsequences with clays which, as a result of theirplasticity, seal the fault surface. In carbonate rocks, theseal is sometimes the result of calcite precipitationalong the fault plane.

Fault traps may be classified, depending on thenature of the fault, as follows: those caused by normal,or gravity, faulting (extensional origin), and those causedby reverse, or thrust faulting (compressional origin).

The simplest normal fault trap interrupts ahomoclinal dip which usually corresponds to the limbof a fold; the most important reservoirs of this type are associated with successions characterized by a regional, homoclinal (or, as is often the case,

bow-shaped) dip, interrupted by a fault contact withimpervious formations or beds.

Normal faults are usually associated with theformation of sedimentary basins. They are mostlysyndepositional and dip towards the subsiding part ofthe basin; their dip thus conforms with the regional dip(synthetic faults or grow faults). They begin to form byflexuring when the basin flexes as a result of thelithostatic load of the sediments, and then develop withthrows of increasing size in the direction of the basin,while sedimentation becomes notably thicker on thelowered sides. A classic example is the coast of theGulf of Mexico, where the faults are still active andaffect populated areas facing the sea.

Other associations of normal faults cut thehomoclinal series with an opposite dip to the regionaldip (antithetic faults); they do not grow over time andare only the result of the compensation of anextensional process.

The most common normal fault traps are related toantithetic faults. In these cases the reservoirs arelocated in the upper part of the uplifted side, when thedislocation places these reservoir rocks in contact withimpervious beds on the lowered side. Naturally,hydrocarbon accumulation occurs after faultdisplacement. Numerous traps are also often found incombination with grow faults on the fault’s loweredside; only a few of them, however, have a seal on thefault plane. An additional factor is required, such as anintersection of faults or a thinning of formations(pinch out, with reference to stratigraphic traps), inorder for a trap to be created.


GEOSCIENCES

0 50 100 150

0

4

8

Shetlandplatform Horda platform

(Bergen High)

Oligocene- Pleistocene

Cormorant

distance (km)

dept

h (k

m)

StatfjordHutton

Palaeocene-Eocene

Upper Cretaceous

Lower Cretaceous

Jurassic

Triassic

basement

W E

Fig. 14. Traps in the Viking Graben, in the North Sea. The faults generating the traps do not extend into the cap, which is slightly bent (North, 1985).

A factor favourable to the accumulation ofhydrocarbons is the association of normal faults whichdetermines the formation of a tectonic horst. The mostuplifted zone is often the site of a reservoir, sealed bythe faults that border it; the zone can also host a seriesof reservoirs, each of which is sealed by one of thefaults that make up the association itself. Reservoirs intectonic troughs (grabens), located on the uppermostsides of the structure, are rarer (Fig. 14). In this contextthere are well-known traps (Red Sea, North Sea) thathave formed only on one side of the trough, when ithas dropped just on one side (half-graben).

Reverse faults form structural traps that are mainlyassociated with folding, which also occurs as a resultof compressional regimes. Their dip is usually lessthan that of normal faults (even less than 45°). Whencompression is greater the fault plane dip tends toapproach the horizontal: in these cases, the termoverthrust is preferred.

The most common traps due to reverse faults havea reservoir in folded formations associated with thefault, and a seal at the lowered side, over which thehydrocarbon-bearing side has slipped. Another pool ofthe same reservoir may be located on the lowered side,corresponding to the fold’s limb, and sealed by thefault itself.

The presence of overthrusts can give rise to traps,especially when they originate in a fold: the upper partof the fold may constitute the reservoir, which may besealed by the thrust-faulted lowered side. At the sametime, the latter may also contain another reservoir thatis capped and sealed by the overthrust side (Fig. 15).

Faults with movement along the direction of thefault plane (strike-slip faults) can also traphydrocarbons if permeable rocks have displaced belowimpermeable ones.

Genesis by compression, which characterizesreverse faults, is also the cause of intense fracturing ofthe rock when the moving limbs consist of hard andbrittle rocks (especially carbonates). The entirefractured zone, in the presence of adequate cap rock,may constitute an excellent reservoir. As alreadydescribed, reverse faults tend to have sealed surfacesmore frequently than normal faults because of theircompressional genesis. In normal faults, the fracturecan stay open more easily and fail to seal the reservoir.

Stratigraphic traps

Stratigraphic traps are caused by a lateral variationin the lithology of the reservoir rock or by aninterruption of the stratigraphic succession (Fig. 16).Lateral variations may be connected to a lithologicalchange, with consequent variation of petrophysicalcharacteristics such as porosity and permeability, or toan interruption in the sedimentation against astructural high (for example, by an onlap). In these



0Mississippian Limestone

NEel

evat

ion

(m) sea

level

SW

Devonian

outwest thrust

1,500

1,500

3,000

Turner Valley thrust

2,000 m

Fig. 15. Structures created as a result of compression (anticlines and reverse faults) generate traps with reservoirs in the Carboniferous (Mississippian Limestone, at the foot of the Rocky Mountains in Alberta) (North, 1985).

1

2

3

4

5 67sea level after continued subsidence

sea level (early stage)

unconformity

Fig. 16. Typology of stratigraphic traps: 1 and 2, real stratigraphic traps; 3 and 4, traps that are positioned, respectively,above and below an unconformity; 5 to 7, paleogeomorphic traps in buried hills(North, 1985).

cases, to have a real trap, the seal must be along thedirection of the beds.

A vertical stratigraphic interruption may entail thepresence of an unconformity with an impervious caprock which seals the trap. Statistically, stratigraphictraps have smaller volumes and are harder to identifyusing geophysical methods than structural ones.Although their existence has been ascertained sincethe Nineteenth century, they have only been exploredin more recent times, not least because they imply athorough and detailed knowledge of the stratigraphicsuccession.

Purely stratigraphic traps are found in reefformations or in lens or channelled deposits. However,a structural component such as porous-permeabledipping beds discordantly capped by impervious rock,is generally also present. For this reason, it ispreferable to describe traps that are characterized byboth components separately, as belonging to thecategory of mixed traps.

Classification of stratigraphic traps will distinguishthe primary ones – which depend on the geometry ofthe reservoir that, in turn, is the direct consequence ofthe characteristics of its sedimentation – from thesecondary ones, formed after sedimentation.

Primary stratigraphic trapsThe different sedimentation processes existing

between rocks with clastic origin and those with achemical-organogenic one give rise to traps withdifferent geometries. Clastic genesis forms traps oflens deposits – often sands and sandstones depositedin particular sedimentation environments withinimpervious clay rocks. In some cases they may beresedimented deposits of breccias of igneous ormetamorphic rocks. They will usually be alluvial ormarine deposits that are the product of currents with ahigh transport capacity along their main axis thatgradually decreases on the sides. For this reason,coarse deposits pass laterally to fine ones, and thislithological passage determines either a gradual orsharp decrease in permeability.

In delta or turbidite deposits, the sand bodies aremainly located in the upper, internal part of the fansand derive from the filling of the channels dew to theflow of the currents. The lateral passage between theselens deposits and the rock that contains them may besharp, as is the case of channels that have beenpreviously eroded and filled with coarse clasticmaterials only slightly more recent than thesurrounding rock.

The hydrocarbons may fill up the coarse bodyentirely or only occupy its upper portion. If the bedshave a homoclinal dip, the hydrocarbons will beconcentrated in the upper part of the bed and trapped

by the permeability barrier that the more clayey,lateral part can provide (Fig. 17). These sand lenses areoften vertically repeated and have an irregular lateraldiffusion, giving rise to reservoirs that are small in sizebut very numerous, and difficult to locate usinggeophysical methods (e.g. the complex of channels inbird’s-foot deltas).

Channelled currents may overflow from thechannel axis, covering non-eroded surroundingdeposits. In this case, extremely thin layers of sandswhose grain size is much finer than that of sandsdeposited in the channels, but with a particularly broadlateral extension (overbank deposits), may be found.The tightly-packed interbedding of thin layers of sandsand clays, which are known as shoestrings because oftheir ample, ribbon-shaped lateral development, maybe the result, not only of the above-mentionedoverflowing phenomena, but also of coastalsedimentation in longshore bars.

Of great importance are the reservoirs contained indeposits of chemical-organogenic origin, mainly incarbonate rocks – especially in those that haveundergone dolomitization with a notable increase inporosity and permeability. Although this process is ofsecondary origin, traps of this type may be classifiedas primary stratigraphic ones because they are tied inwith the sedimentation environment.

The presence of hydrocarbons in reef formations isfavoured by the fact that the rock that contains themmay have been the source rock; they migrate to theupper part of the formation, into a trap with a cap rockof clay sediments that deposited when the reef ceasedto develop. The lateral seal is often made up of the


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X X� X X�

X X� X X�

section water

oil

section water

permeable

impermeableimpermeable

plan

porous and permeable

plan

oil

Fig. 17. Primary stratigraphic traps: A, porous-permeable lens in an impermeablerock; B, lens in a homoclinal regional dip with trap caused by the passage to an impermeable rock (Levorsen, 1956).

A B

impermeable basin sediments deposited in heteropyduring the growth of the reef.

Carbonate shelf sediments, which are also oftendolomitized, are widespread as well; they have a muchmore ample lateral development than reef sediments,and are of a similar thickness, given that they toodevelop vertically to compensate subsidence.Reservoirs located in the above-mentioned sedimentsare more ample than those found in reef formations,and their cap may take the form of terrigenousplatforms with a considerable clayey matrix on top, orlimestones that have not undergone dolomitization andhave therefore maintained their impervious properties.

Stratigraphic traps associated with unconformities(or of the secondary type)

A stratigraphic unconformity occurs as a result ofan interruption in the sedimentation process (asedimentary hiatus). The surface distinguishing aninterruption is erosive if the most recent part of thesuccession has been dismantled or carried away byerosion agents, in particular when an uplift hasmoved the rock into a subaerial environment. In thiscase, the surface may be irregular and highlyarticulated, with fluvial incisions, reliefs anddepressions. After a transgression, the marinesedimentation resumes and covers the unconformitywith a new cycle which, as a result, constitute a caprock. Stratigraphic studies and basin analysis are thefirst steps in recognizing unconformity traps withinthe basin itself.

Usually, the part that was uplifted will also havebeen dislocated, and bedding is deformed in differentways with folds and faults; a new undeformedsuccession is deposited on top of it (angularunconformity). The truncation of beds folded belowthe unconformity, which is followed by the depositionof impermeable layers, generates a typicalstratigraphic trap. In other cases, erosion may act onan area that has been uplifted at the regional level,even without deformation (disconformity).

Finally, an interruption of the sedimentationprocess, especially if the succession remains in amarine environment, may be followed by a newsedimentation cycle without the succession sufferingeither erosion or deformation as a result(paraconformity). In this case it is recognized only bythe absence of a chronological interval, which may bepalaeontologically identified. At the transition betweenold and new sedimentations only incrustations formedduring the non-deposition interval or, if the surface hasbeen exposed to atmospheric agents, a hardenedpalaeosol (hard-ground), may be observed.

If the succession on top of the unconformity has animpervious base, the latter will constitute a cap rock

for the underlying portion. By migrating along theporous-permeable formations, the hydrocarbons mayaccumulate in one or more reservoirs at the porous-permeable intervals, which are separated from oneanother by the impervious layers of the succession.Other traps may be located just below theunconformity in the part that was eroded, exposed toatmospheric agents, and, therefore, altered and porous.Finally, sands or gravel contained in the palaeochannelsof rivers or coastal deposits overlying theunconformity may give rise to good reservoirs.

The erosion profile presents buried hills orlandforms that constitute palaeogeomorphologic traps.A stratigraphic succession may contain variousunconformities (in some cases, an upper one may cutthrough a lower one), and each of these may give riseto overlying traps representing the result of themigration and accumulation processes below eachunconformity. In particular, the uplift of an anticlinemay occur in various phases that are progressivelyattenuated, each separated from the older one by anunconformity.

Mixed (stratigraphic-structural) traps

These are traps in which both structuraldeformations and stratigraphic variations occur. Themost important of these are related to the existence ofsalt domes, which result from the uplift of relativelylight rocks, usually halite and gypsum of evaporiticorigin. Halite has a density of about 2.2 and gypsum ofabout 2.4. Experiments conducted in the Gulf ofMexico have shown that, as a result of the geostaticload, the density of sediments associated with saltincreases progressively with depth and that, at a depthof 700 m, it is already greater than that of salt, whichis incompressible and therefore always maintains thesame density.

In the presence of water and at high temperatures,salt and gypsum become extremely plastic. Thereforea slight deformation, such as an anticline, and evenone with a wide radius, may cause an uplift in the saltlayers known as a diapir, starting from the fold’s hinge.The salt formations, because of their plasticity,literally pierce the overlying rocks with an upwardhydrostatic thrust, as described by Archimedes’principle which establishes the tendency towardsequilibrium of lighter and heavier masses: a salt domeis thus created. Its structuring, and above all the speedat which the light salts rise, are proportional to thevolume of the masses involved in the process.

As a result of their increased density the sedimentscontouring the salt structure begin to exert a lateralpressure that affects the shape of the dome, oftencausing it to become narrower at the bottom. In other



words, the dome may have a wider diameter at the top,where it is less influenced by lateral pressure, than atgreater depths.

The rise of the salt is favoured in corrugated zoneswhere the diapiric salt masses have varied shapesbecause the overlying rocks, which have sufferedfolding and fracturing, offer different amounts ofresistance to the upward thrust of the salt, dependingon the direction of the discontinuity. Favoured by itsown plasticity, the salt tends to proceed along theeasiest paths, intruding into the weakened zones andacquiring irregular shapes.

Salt rocks are impervious and the formations thatcontour the dome may be the site of importantreservoirs, sealed by the salt itself (Fig. 18). Theupward motion of the salt provokes an uplift of thesurrounding beds which, as a result, are generallymore inclined. In the case of porous-permeable rocks,these beds give rise to reservoirs with a limited lateralextension but a pronounced vertical development, andare marked by an anomalous pressure, greater thanthat considered normal at those depths. It should benoted that the salt domes, which only rarely reach thesurface, are, as a result of their low density, easilyidentified in the subsurface by means of gravimetricsurveys. Their shape is that of a truncated cone orirregular cylinder, often with a mushroom-shaped

upper part, diameters of around one kilometre andheights of up to several thousand metres.Hydrocarbons are produced from wells positionedaround the dome and, in part, on the cap rock on thedome itself.

The formation of a salt dome may cause a numberof normal faults to be associated with the blocks thatthe dome has uplifted; in this case, the traps are notsealed by the salt walls but by the impermeableformations that are interbedded with the porous-permeable ones of the succession.

Much has been written about salt domes owing tothe frequency with which they occur on the coast ofthe Gulf of Mexico, in Louisiana and in Texas. The saltdomes in this area are known as salt plugs, and areformed by halite associated with anhydrite; because ofits high density, however, anhydrite does not give riseto diapirs. Free sulphur derived from the anhydrite,and potassium salt are also often present. Theformations that cover the salt domes are marked bynumerous faults that radiate out from the centre of thedome, with vertical dislocations of several hundreds ofmetres. These highly dipping faults lead to theformation of reservoirs in separate blocks, some ofwhich are true tectonic troughs (grabens) mostlylocalized above the domes. In these cap rocks,excellent reservoirs are formed in interbedded sands(for example, the Frio Formation in Texas).

The upward-thrust phenomenon gives rise to someextremely complicated structures, in which the faultsare associated with squeezing and truncation of thesand formations that contour the dome; these structuresmay contain ten or more pools. Exploration is thereforevery complicated, and the drilling stage may beproblematic due to the overpressure of the clays.

In addition to the Gulf of Mexico, there are manyother production areas related to salt domes: theHanover zone (Germany), the region to the north ofthe Caspian Sea, and various areas in the Middle East,especially in Iran.

Other typical mixed traps occur when thedislocation takes place during the sedimentationprocess (syntectonic sedimentation). This can occur inbasins that are only partially affected by deformations:while one part rises, forming a structural high, the restis subject to sedimentation. The basin’s sands onlap theupraised part, and change lithofacies, becomingthinner, more clayey and less permeable. The endacquires a characteristic lens or pinch-out shape.Bearing in mind that this, too, may have been lifted,the sand layer may end by arching upwards andbecoming a reservoir blocked by the passage to theclayey facies or by the flank of the structural high. Inpractice, the structural high is contoured by thesepinched-out lens sands that can lie on top of each


GEOSCIENCES

salt plug

cap rock

Fig. 18. Idealised section of a salt dome in the Gulf of Mexico. In black, the oilcontained in traps of various types (by fault in the cap rock; by unconformity at the dome’s sides). The seals may consist of salt or impermeable rocks interbedded in the sedimentary succession (Levorsen, 1956).

other, separated by layers of clay, and give rise toseveral overlying reservoirs.

The structural high may be represented by a saltdome that has risen after the sedimentation of thesurrounding basin (in which case it may form a trap ofthe kind already described), or during it, in which caseit may form mixed traps with pinched-out sandterminations.

Other mixed traps may occur when a fault planeproduces a slope along which the sediments previouslydeposited on the uplifted flank either slump down orlandslide (megabreccias).

If the water in a reservoir rock is in motion, the oil-water contact assumes the same dip as that of thewater’s movement. Hydrodynamic traps of various

shapes and sizes, depending on the characteristics ofthe porous-permeable rock in which the reservoir islocated, may thus be generated (Fig. 19).

Other mixed traps are associated with anticlinesformed, not as a result of tectonic actions, butof the buried hills mentioned above: the beds,dipping radically over the hills, forms reservoirsalong their borders, often where there areaccumulations of coarse products produced by thedisintegration of the hills.

In other cases, the trap originates as aconsequence of differential compaction underlithostatic load, as clays are more compressible thanother rocks, such as sand. In a covering successionwith high clay content, the sequence is more compactwhere the thickness is greatest. As a result, there willbe a culmination on the buried hill, where the cover isless thick, while the clays, which are more abundanton the borders, will be more compact, therebysimulating an anticline.

The buried hill may also not be erosive in nature:for example, a reef covered by a thin bed of clay(which may have determined the extinction of the reefitself) will usually be flanked by basin deposits of aclayey nature that are subject to compaction; they toosimulate an anticline that may be the site of reservoirsseparated from the reef.

The variety and complexity of the geologicalconditions related to the presence of hydrocarbonreservoirs and their relative caps, together with theexistence of traps, are the basis of oil exploration.Once an oil region has been identified, explorationusually involves the following steps:• Identification and drilling of structural traps, which

are easier to identify by means of geophysicalsurveys. At this point, subsurface exploration willhave provided useful stratigraphic information forthe next step.

• Search for and drilling of mixed traps.• Exploration of stratigraphic traps, carried out on

the basis of an accurate stratigraphic study basedon data collected during the first two steps.

References

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Bosellini A. (1991) Introduzione allo studio delle roccecarbonatiche, Ferrara, Bovolenta.

Casnedi R. (1991) Hydrocarbon accumulation in turbidites inmigrating basins of the Southern Adriatic foredeep (Italy),in: Bouma A.H., Carter R.M. (editors) Facies models inexploration and development of hydrocarbon and oredeposits. Proceedings of the 28th International geologycongress, Washington (D.C.), 9-19 July 1989, VSP, 219-233.



A

B

C

gasoil water

Fig. 19. Types of hydrodynamic traps in a thick and deformed anticlinal sand body:A, gas and oil in complete superposition; B, gas in partial superposition; C, the gas and oil accumulations are separate(Magara, 1977).

A

B

C

Casnedi R. et al. (1977) Geologia del campo gassifero diCellino (Abruzzo), «Bollettino della Società GeologicaItaliana», 95, 891-901.

Downey M.W. (1994) Hydrocarbon seal rocks, in: MagoonL.B., Dow W.G. (edited by) The petroleum system. Fromsource to trap, Tulsa (OK), American Association ofPetroleum Geologists, 159-164.

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Magoon L.B., Dow W.G. (edited by) (1994) The petroleumsystem. From source to trap, Tulsa (OK), AmericanAssociation of Petroleum Geologists.

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Pleistocene Adriatic foredeep (Central Italy) from surfaceand subsurface data, in: Spencer A.M. (editor) Gener-ation, accumulation and production of Europe’s hydrocar-bons III, Berlin-New York, Springer, 233-258.

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Ricci Lucchi F. (1986) The Oligocene to recent foreland basinsof the Northern Apennines, in: Allen P.A., Homewood P.(edited by) Foreland basins, Oxford, Blackwell, 105-139.

Selley R.C. (1988) Applied sedimentology, London, AcademicPress.

Taylor J.C.M. (1977) Sandstones as reservoir rocks, in:Hobson G.D. (edited by) Developments in petroleumgeology, London, Applied Science Publishers, 2v.; v.I,147-196.

Vail P.R. et al. (1977) Relative change of sea level from coastalonlap and global cycles of relative changes of sea level,in: Payton C.E. (edited by) Seismic stratigraphy. Applicationto hydrocarbon exploration, Tulsa (OK), AmericanAssociation of Petroleum Geologists, 63-98.

White J.C. (1885) The geology of natural gas, «Science», 5,521-522.

Zimmerle W. (1995) Petroleum sedimentology, Dordrecht-Boston, Kluwer Academic Publishers.

Raffaele CasnediDipartimento di Scienze della Terra

Università degli Studi di PaviaPavia, Italy


GEOSCIENCES

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