Reservoir Engineering note 5 Petroleum Geology-converted

Reservoir Engineering

Petroleum Geology (Part 1)

Petroleum geology is a branch of geology that focuses on the exploration, production, and development of oil and gas resources. It involves the study of the geological processes that lead to the formation, migration, and accumulation of hydrocarbons in subsurface reservoirs. Petroleum geologists play a crucial role in identifying potential oil and gas reservoirs, assessing their quality and quantity, and optimizing drilling and production strategies for efficient extraction of hydrocarbons. In this comprehensive discussion, we will delve into the key concepts, principles, and techniques of petroleum geology, covering topics such as sedimentary basins, source rocks, reservoir rocks, traps, and exploration methods.

The Habitat of Petroleum

A sedimentary basin is an area of the Earth's crust where sedimentary sequences are much thicker than those found in surrounding areas. Oil and gas commonly occur in sedimentary basins, whilst being absent from intervening metamorphic and igneous rocks. Most sedimentary basins cover tens of thousands of square kilometres, and may occur as part of a mountain chain, beneath a continental 'peneplain' or under an ocean. There are more than 600 sedimentary basins Worldwide and over a quarter of them produce petroleum.

Figure 1. Sedimentary Basins Around the World (From THE DYNAMIC EARTH by B.J. Skinner and S.C. Porter, copyright © 2000 John Wiley and Sons. This material is used by permission of John Wiley and Sons, Inc.).

• Areas underlined by sedimentary rock (in the ocean to a depth of 2000m)
• Areas of ocean deeper than 2000m underlined by thick accumulations of sedimentary rocks
• Areas when major amounts of oil and gas have been found

There are five essential requirements for the formation and preservation of oil and gas. For these five requirements, a sedimentary basin with a thickness of at least 2500 to 5000m of sediment is needed to ensure that the source rocks are mature to the oil generation threshold. The "magic five" are:

1. a source rock: fine grained shale or limestone with a minimum of 0.5% petroleum producing organic matter;
2. heat is required to generate petroleum from the organic matter. The oil window is from 60° C to 120° C for the production of oil and up to 180° C for the production of gas;
3. a reservoir rock that is both porous and permeable and of sufficient thickness, sandstone and limestone;
4. an impermeable cap rock or seal composed of fine grained shales or evaporite;
5. a trap, structural, stratigraphic, combination or hydrodynamic, where the migration of petroleum is barred. The trap must have been emplaced before the migration. Once trapped the oil must not be buried too deep that it is destroyed or be allowed to escape by subsequent faulting.

Any thick sedimentary sequence may contain these ingredients and are thus important for petroleum exploration. As a general rule we can expect to find gas in the deepest parts of the basin, light oils in the intermediate zone and heavier oils in the basin margins. Hydrocarbon distribution within a basin is related to both the thermal maturation of the source beds and the permeable migratory paths. For example, gas requires higher temperatures for formation and will therefore be more prevalent at depth unless allowed to migrate. A mixture of oil and gas that is allowed to migrate up and across a basin will fill traps as it travels. Gas is less dense and will therefore spill from a trap after the oil. As a result deeper traps will contain gas, and shallower traps, oil. As always, however, local conditions will produce exceptions to this, the Niger Delta being an example.

Sedimentary Basin Formation

Formation of a sedimentary basin of sufficient size to produce and trap hydrocarbons can occur via several mechanisms. The formation of a topographic basin itself, however, does not mean that it will fill with sediment. This will be dictated by local conditions. The shape of the basin, the position of the thickest sediments within, and the type of those sediments, will depend upon whether the deposition occurred at the same time as the basin or before, and upon the method of sediment transfer to the region. For example, a basin may be filled with sediment as it is formed, or, as it may form at a time after deposition of sediments in that region (Figure 2). This will relate to the type of trapping structures likely to occur within the basin, when they were formed in relation to kerogen maturation, and hence the probability of finding oil. The method of sediment transfer will influence sediment topography. Deltaic sediments will tend to advance in a linear fashion, for example, and the greatest thickness may not necessarily coincide with the maximum basin depth.

Figure 2. Sediment Thickness and Sediment Type in Relation to Deposition Time (after Selley, 1998).

Basin formed after deposition | Basin formed concurrent with deposition

Continental sediments | Intermediate sediments | Deep marine sediments

Basin contour | Paleocurrent

Reservoir Rocks

The reservoir is the portion of rock containing the pool of petroleum. It is usually composed of unmetamorphosed sedimentary rocks, such as sandstones, limestones and dolomites. However, reservoirs do, rarely, occur in igneous, metamorphic and shale rocks. Pools of hydrocarbons accumulate within rocks that have enough space to accommodate them. For commercial viability, this pool must be big enough. What is regarded as "big enough" depends on many factors including porosity, permeability, and location of the reservoir and proximity to other reservoirs or fields. A reservoir formation must have both porosity and permeability.

Porosity, or the presence of void spaces, enables the rock to contain hydrocarbons and other fluids. The greater the porosity, the greater the holding characteristics of the rock. Porosity alone however does not make recovery of formation fluids possible. If all the pore spaces are sealed off after hydrocarbon migration, recovery will be high on impossible as no fluid will be able to flow through the rock. For this to be viable the rock also needs permeability. Permeability is a measure of the ease of fluid flow through the rock, ie, the connectivity between the pore spaces.

Porosity

Void spaces within most rocks usually contain connate water. It is this water which is displaced due to hydrocarbon migration. Porosity can be expressed as a void ratio or percentage.

Porosity (φ) = (Volume of voids / Bulk volume) × 100%

Porosity is independent of grain size, but is affected by sorting and roundness of grains. Pores take on three different morphologies (Figure 3).

Figure 3. Pore morphology

Hydrocarbons can be recovered from catenary and cul-de-sac pores but not from closed pores. Catenary pores may be flushed out by natural or artificial water flow, whereas cul-de-sac pores will only produce hydrocarbons due to expansion as reservoir pressures drop. The ratio of total to effective porosity is important as it relates directly to permeability. Most reservoirs are water wet. This means that, even in an oil sand, there will be a thin film of water attached atomically to the surface of each grain (Figure 4). It cannot be removed and is known as the irreducible water content (Sw).

Figure 4. Irreducible Waterfilms

This film of water will occupy a proportion of the pore space and will therefore reduce the porosity of the reservoir. We define the effective porosity of the reservoir as:

Effective porosity = porosity × (1 - Sw)

Since in a fine grained rock the pore spaces are small, the irreducible water content will affect a greater proportion of the porosity. Effective porosity is therefore affected by grain size.

Nature of Porosity

Porosity can be defined as primary or secondary. Primary porosity is that present after deposition on first burial, whereas secondary porosity is that formed sometime after deposition. Primary porosity will only be maintained if the grains are not altered, fractured or dissolved in any way and depends on factors such as:

• uniformity of grain size;
• grain shape;
• manner of packing, which is related to the above;
• effects of compaction after deposition.

Primary porosity may be further broken down into two subsets, namely, intergranular (interparticle) and intragranular (intraparticle). Interparticle pores are present in all sediments initially, but are often lost quickly in carbonate sands and shales due to compaction and cementation. Intraparticle pores are generally found within skeletal grains (fossils) of carbonate sands. Compaction and cementation again, may destroy this. Most of the porosity in sandstone is preserved primary interparticle porosity. In theory, the grain size should make no difference to the percentage of porosity.

However, large grained sediments are much more likely to have a wide variety of grain sizes. Smaller grains will take up the pore spaces between larger grains. Hence fine overall grained sediments may have higher porosities than course grained sediments. Uniform spherical grains have a higher theoretical porosity than that of angular grains. However, in practice, spherical grains pack with minimal porosity, as absolute uniformity of grain size is never achieved, whereas angular grains tend not to. The highest porosity is often found in sediments containing well sorted angular grains. Porosity as can be seen is highly dependent on sorting. Packing helps sort grains according to size but also tends to make the rock as tight as possible. Packing is an ongoing process during rock formation as depositional packing will be followed by postdepositional packing and then compaction under increasing loads produced by burial. Compaction deforms the rock grains in an irreversible manner past their elastic limit.

Secondary porosity is generally referred to as the occurrence of extra pore spaces caused by post-depositional and diagenetic processes. In sandstones, modification of primary porosity is due mainly to interlocking of grains through compaction, contact solution and re-deposition, and to cementation. In carbonates, the principle modifications are due to solution, recrystallisation, fracturing and cementation. Sandstones and carbonates therefore have very different natural porosity characteristics. Due to continued burial, however, unless secondary porosity is formed at a rate in excess of the loss due to compaction, the total resultant porosity may in fact be less than the original primary porosity.

Porosity Measurement

There are several techniques for porosity measurement. The most direct techniques in the laboratory involve the withdrawal of air from the pore spaces using a vacuum, and measurement of the volume of displaced air. This combined with a calculation comparison to the bulk sample volume can be used to determine porosity. For elastic reservoirs the measurements are commonly made on quite small samples or core plugs. For carbonate reservoirs, however, the nature of the porosity may be insufficiently homogeneous for the use of small samples to give accurate readings. The presence of vugs for instance may be completely missed. Full core samples are generally used for analysis of carbonate reservoirs therefore. Porosity may also be measured indirectly from geophysical well logs and seismic data.

Permeability

Permeability is the property of a medium of allowing fluids to pass through it without change in the structure of the medium or displacement of its parts, or more simply, a measure of the ease of which a fluid will pass through a rock. It can be defined from the relationship:

Q = (K × (P₁ - P₂) × A) / (μ × L) (Darcy's Law)

Symbol	Meaning
Q	rate of flow
K	permeability
(P₁ - P₂)	pressure drop across sample
A	cross sectional area
L	length of sample
μ	viscosity of fluid

The unit of permeability is the Darcy (from H.Darcy who carried out the original work on permeability in the 1850's) and is defined as the permeability that allows a fluid of 1 centipoise viscosity to flow at a velocity of 1 cm/s for a pressure drop of 1 atm/cm. Permeability is a property of the rock. The higher the permeability the faster, and therefore the more economic, the well production. The presence of irreducible water content reduces the permeability, and it is the job of the petroleum engineer to calculate the effective or relative permeability. Permeability is measured in millidarcies (md). Average reservoirs have permeabilities of between 5-1000 Md.

Reservoir Types

The presence of oil and gas in appreciable quantity within a rock does not mean that their recovery is viable, either commercially or practically. Any rock however containing hydrocarbons and possessing the suitable porosity and permeability characteristics enabling recovery is a reservoir rock. Generally reservoirs are considered as two basic types, elastic reservoirs (mainly sandstones) and chemical reservoirs (mainly carbonates - limestone or dolomite). Sandstones are wholly inorganic in origin, whereas limestones are at least partially organic or chemical in origin, even if they are now in a elastic state. A small proportion of reservoirs are found in other rock types.

Nature of Petroleum

Petroleum consists of a mixture of various classes of chemical compounds. The relative amounts of these compounds determine the properties of petroleum. Each compound is made up of atoms joined together according to a number of bonds. The commonest elements are carbon (symbol C; 4 bonds) and hydrogen (Symbol H; 1 bond) - hence hydrocarbons. Other minor elements include: oxygen (O; 2 bonds); nitrogen (N; 3 bonds) and sulphur (S; 2 bonds). The compounds can be described based upon:

• a systematic naming based on structure;
• formulae giving the elements present and relative numbers of each;
• as pictorial representations.

What is an Organic Compound?

Even though organic chemistry focuses on compounds that contain carbon and hydrogen, more than 95% of the compounds that have been isolated from natural sources or synthesized in the laboratory are organic. The special role of carbon in the chemistry of the elements is the result of a combination of factors including, the number of valence electrons on a neutral carbon atom, the electronegativity of carbon, and the atomic radius of carbon atoms.

Carbon forms covalent bonds with a large number of other elements, including the hydrogen, nitrogen, oxygen, phosphorus, and sulfur found in living systems. Because they are relatively small, carbon atoms can come close enough together to form strong C-C single bonds, C=C double bonds or even C≡C triple bonds. Carbon also forms strong double and triple bonds to nitrogen and oxygen. It can even form double bonds to elements such as phosphorus or sulfur that do not form double bonds to themselves. The chemical and physical properties of carbon provide for an almost infinite variety of potential structures for organic compounds, and provide the basis for all life on planet Earth.

The Saturated Hydrocarbons, or Alkanes

Compounds that contain only carbon and hydrogen are known as hydrocarbons. Those that contain as many hydrogen atoms as possible are said to be saturated. The saturated hydrocarbons are also known as alkanes. The simplest alkane is methane: CH₄. The Lewis structure of methane can be generated by combining the four electrons in the valence shell of a neutral carbon atom with four hydrogen atoms to form a compound in which the carbon atom shares a total of eight valence electrons with the four hydrogen atoms.

H
|
H - C - H
|
H

Methane is an example of a general rule that carbon is tetravalent; it forms a total of four bonds in almost all of its compounds. To minimize the repulsion between pairs of electrons in the four C H bonds, the geometry around the carbon atom is tetrahedral (Figure 5). The angle between the bonds is 109.5°.

Figure 5. Tetrahedral Structure of Carbon Bonding in Methane

The naming sequence continues, ethane (C₂H₆), propane (C₃H₈), and butane (C₄H₁₀) for alkanes containing two, three and four carbon atoms respectively. The names, formulas, and physical properties for a variety of alkanes with the generic formula CₙH₂ₙ₊₂ are given in Table 1. The boiling points of the alkanes gradually increase with the molecular weight of these compounds. At room temperature, the lighter alkanes are gases; the midweight alkanes are liquids; and the heavier alkanes are solids, or tars.

Table 1. Some Alkanes in Series.

Name	Molecular Formula	Melting Point (°C)	Boiling Point (°C)	State at STP
methane	CH₄	-182.5	-164	gas
ethane	C₂H₆	-183.3	-88.6	gas
propane	C₃H₈	-189.7	-42.1	gas
butane	C₄H₁₀	-138.4	-0.5	gas
pentane	C₅H₁₂	-129.7	36.1	liquid
hexane	C₆H₁₄	-95	68.9	liquid
heptane	C₇H₁₆	-90.6	98.4	liquid
octane	C₈H₁₈	-56.8	124.7	liquid
eicosane	C₂₀H₄₂	36.8	343	solid
triacontane	C₃₀H₆₂	65.8	449.7	solid

The alkanes above are all straight-chain hydrocarbons, in which the carbon atoms form a chain that runs from one end of the molecule to the other. The generic formula for these compounds can be understood by assuming that they contain chains of CH₂ groups with an additional hydrogen atom capping either end of the chain. Thus, for every n carbon atoms there must be 2n + 2 hydrogen atoms: CₙH₂ₙ₊₂.

Figure 6. Ethane, Propane and Butane Molecules

In addition to the straight-chain examples considered so far, alkanes also form branched structures. The smallest hydrocarbon in which a branch can occur has four carbon atoms. This compound has the same formula as butane (C₄H₁₀), but a different structure. Compounds with the same formula and different structures are known as isomers (from the Greek isos, "equal," and meros, "parts"). When it was first discovered, the branched isomer with the formula C₄H₁₀ was therefore given the name isobutane (Figure 7).

Figure 7. Isobutane.

Butane and isobutane are called constitutional isomers because they literally differ in their constitution. One contains two CH₃ groups and two CH₂ groups; the other contains three CH₃ groups and one CH group. There are three constitutional isomers of pentane, C₅H₁₂ (Figure 8).

The first is "normal" pentane, or n-pentane. A branched isomer is also possible, which was originally named isopentane. When a more highly branched isomer was discovered, it was named neopentane (the new isomer of pentane).

Figure 8. Isomers of Pentane.

There are two constitutional isomers with the formula C₄H₁₀, three isomers of C₅H₁₂, and five isomers of C₆H₁₄. The number of isomers of a compound increases rapidly with additional carbon atoms. There are over 4 billion isomers for C₃₀H₆₂, for example.

The Unsaturated Hydrocarbons: Alkenes and Alkynes

Alkenes

Carbon not only forms the strong C-C single bonds found in alkanes, it also forms strong C=C double bonds. Compounds that contain C=C double bonds were once known as olefins (literally, "to make an oil") because they were hard to crystallize. (They tend to remain oily liquids when cooled.) These compounds are now called alkenes. The simplest alkene has the formula C₂H₄.

Because an alkene can be thought of as a derivative of an alkane from which an H₂ molecule has been removed, the generic formula for an alkene with one C=C double bond is CₙH₂ₙ. The series continues ethene, propene, butene.

Alkynes

Compounds that contain C≡C triple bonds are called alkynes. These compounds have four less hydrogen atoms than the parent alkanes, so the generic formula for an alkyne with a single C≡C triple bond is CₙH₂ₙ₋₂. The simplest alkyne has the formula C₂H₂ and is known by the common name acetylene. Again the series follows the same pattern of naming.

The alkanes, alkenes and alkynes are generally grouped together as a class of organic compounds known as the Aliphatics, often termed paraffins.

For all paraffins:

• if n < 5 they are gaseous at STP;
• 5 < n < 15 they are liquid;
• n > 15 they are solid.

The Cycloalkane or Napthene Compounds

If the carbon chain that forms the backbone of a straight-chain hydrocarbon is long enough, we can envision the two ends coming together to form a cycloalkane. One hydrogen atom has to be removed from each end of the hydrocarbon chain to form the C-C bond that closes the ring. Cycloalkanes therefore have two less hydrogen atoms than the parent alkane and a generic formula of CₙH₂ₙ. The smallest alkane that can form a ring is cyclopropane, C₃H₆, in which the three carbon atoms lie in the same plane (Figure 9, left). Following convention, cyclohexane is a six carbon atom ringed alkane (Figure 9, right).

Figure 9. Cyclopropane and Cyclohexane Rings

The Aromatic Compounds

The aromatic hydrocarbons include benzene and the alkyl derivatives of benzene, a six sided unsaturated ring. There is no general formula. Toluene is the most common aromatic compound of crude oil, followed by xylenes and benzene itself. Any compound with the benzene ring is an aromatic compound.

Heteroatomic Compounds

Heteroatomic compounds refer to all the other elements found in hydrocarbons except for hydrogen and carbon. These include: oxygen; nitrogen and sulphur.

Metallic Compounds

Metallic compounds also occur in hydrocarbons. Vanadium, copper and nickel all form oil soluble complexes.

Types of Petroleum

Hydrocarbons are a physically diverse group ranging from gases to liquids to solids.

Natural Gas

Natural gas is a mixture of Hydrocarbon and Non-hydrocarbon gases. They can occur subsurface as dissolved (in solution in oil under subsurface pressures); as associated gas (as a gas cap) or as non-associated gas (a commercial gas deposit in its own right – no oil present). Gas dissolved in oil will act like a "coke bottle". Under pressure gas will be in solution but as oil migrates upwards the pressure will decrease and the gas will bubble out of the oil and form a cap.

Hydrocarbon gases are predominantly from the paraffin group: methane, ethane, propane, butane. Non-hydrocarbon gases include: carbon dioxide; nitrogen; helium. Dry gas refers to gas with no liquid vapour content (methane). Wet gas has liquid vapour content (ethane, propane, butane). Sour gas indicates the presence of hydrogen sulphide.

Non hydrocarbon gases are sometimes present in large quantities and are sometimes of commercial value in their own right. Helium enriched gases can form up to 8% of the weight in some areas. Economically significant amounts are found in Texas, Alberta, Poland and Queensland. Nitrogen enriched gases are found in the North Sea and the Gulf of Mexico. 14% by weight of the Groningen field gas in the Dutch sector is nitrogen. Argon, radon, carbon dioxide and hydrogen sulphides are also found. The latter is particularly nasty.

Gas Hydrates

Hydrates are compounds of frozen water containing gas molecules. The gas may include methane, ethane or carbon dioxide. They occur only in highly specific temperature/pressure regimes. Hydrates are only stable at high pressures and low temperatures. They occur in shallow arctic sediments and deep oceanic deposits. They have also been found in active permafrost zones in Alaska and Siberia. They are potentially an important energy source as ice molecules can hold up to 6 times as much gas as the normal open pore system found in reservoirs.

Condensates

Condensates are gaseous at subsurface pressures but liquify as pressures decrease at the surface.

Crude Oil

Crudes vary widely in composition, density, colour (from green, yellow, brown, black) and viscosity. They are defined, and the price of crude is largely fixed, on the density of the crude as specified by the American Petroleum Institute (API). The API specify the scale of crude density in degrees according to the following empirical equation:

API = (141.5 / SG) - 131.5

Where SG is the specific gravity of the oil at 60° F as compared to that of water at 60° F.

Generally the following apply:

• young-shallow oils are heavy, viscous and low in paraffins;
• young-deep oils are less viscous, have high API values and are lighter with more paraffins;
• old-shallow oils are also less viscous, have high API and are lighter with more paraffins;
• old-deep oils are more viscous and are heavy with low API values.

Solid/Plastic Hydrocarbons

Asphalts and resins are semi-solid to solid materials with melting points of approximately 150-200° F. They are fairly soluble, soft, tarry and will flow when heated.

Asphaltenes are hard, brittle solids with higher melting points of over 300° F. They are denser and less soluble than the asphalts and contain large amounts of oxygen and sulphur.

Bitumens are the most dense they swell and explosively decompose when their melting point is reached. They are insoluble.

Formation Brines

Oil is always found in contact with water. This water is the remains of the formation water that originally filled the pores of the reservoir rock before being displaced by hydrocarbons. Brines are named according to, their relative position to the oil bearing strata: top, intermediate, bottom, edge, or, their history. Meteoric waters are relatively dilute containing carbonate and have recently been in atmospheric circulation. Connate waters are those derived directly from the original water in which the sediments were deposited. Interstitial or formation water refers to water in place at the time of drilling. Diagenetic waters are waters that have been altered during the diagenesis process.

Hydrocarbon Generation

Organic Matter

Although there is sound evidence to support the formation of hydrocarbons due to natural physical and chemical processes within the deep crust or mantle, these abiogenic formations are rare and do not yield commercially viable sources of petroleum. The petroleum we drill for today is of biogenic origin and formed by the thermal maturation of organic matter.

The key to the transfer of inorganic carbon to hydrocarbons is photosynthesis. Plants and algae take carbon from the atmosphere, mainly from carbon dioxide, and combine it with water to form glucose. Glucose is the starting point for conversion into more complex organic compounds and formation of higher life forms. Under most common circumstances, when plants and animals die, the organic matter is oxidised to form carbon dioxide and water, thus completing the carbon cycle. However, under some circumstances, if the organic matter is buried rapidly, it may be preserved, leading in time to the formation of petroleum.

The amount of matter buried will depend on the ratio of organic productivity and destruction. The organic matter will die and rain down on the sediment below. Gradually subsequent layers during the process of sedimentation will bury this sediment, and eventually form potential source rocks. The organic matter must be preserved in order to lithify and form source rocks. Oxidation or predation can destroy organic matter.

The following enhances preservation:

• a high sedimentation rate and a rapid burial process;
• fine grain size so that oxygen cannot penetrate and oxidise material;
• anoxic bottom water conditions.

These conditions are most often found in shales and fine grained limestones. All of which are common source rocks. The kind and amount of petroleum that is generated from these deposits depends on three main factors:

• the nature of the remains of living organisms preserved in the sediments;
• the abundance of this organic matter;
• the extent to which this matter has been 'cooked' or 'matured'.

For a shale to act as a source rock it must contain organic matter amounting to at least 0.5% by weight. In the northern North Sea organic content is at least 5%. If the figure is above 50% the rock is referred to as an Oil Shale. Only approximately 70% of the organic matter will be converted to petroleum and not all of this will migrate from the source rock. The 'expulsion efficiency' depends on the thickness of the source rock and the availability of migration pathways.

Formation of Kerogen and Petroleum

Once organic deposits have been buried and preserved, certain physical and chemical processes must also take place for the transformation into petroleum to occur. These processes are a consequence of increasing burial depth with time, which exposes the organic deposits to both increasing temperature and pressure.

There are three major phases involved in the 'maturation' or 'cooking' of this matter to form oil and gas:

• Diagenesis, formation of kerogen;
• Catagenesis, maturation of kerogen;
• Metagenesis.

Zone of Diagenesis

This zone is found in the top few cm of the surface sediment at near normal temperatures and pressures. Biogenic decay, aided by bacteria, and some abiogenic reactions are involved.

The pH and Eh adjacent to the sediment/water interface is controlled largely by the bacteria types present. If the water is stratified, as discussed earlier, an aerobic oxidising zone (+Eh) overlies an anaerobic reducing zone (-Eh). The interface between these two zones may be within the water column, at the interface, or if the sediment is permeable, below the sediment line. This oxic/anoxic alkaline (ph 7 – 9) transition zone is perfect for certain types of bacterial decay. In the reducing zone, anaerobic sulphate reducing bacteria attack the organic material and remove oxygen from sulphate ions, releasing sulphur and sulphides, whilst in the oxidising zone, sulphur oxidising bacteria oxidise the sulphur again. Abiogenic reaction of organic matter with sulphate ions will also lead to the release of hydrogen sulphide.

Methane, carbon dioxide and water are given off during these reactions, leading to the formation of kerogen. The end result during this diagenesis is the reduction of oxygen content, leaving the hydrogen: carbon ratio much the same as the original matter. The type of kerogen produced, therefore, depends on the original type of organic matter deposited. This will in turn determine the final type of petroleum products after maturation. Sediments in the zone of diagenesis are termed 'immature'. In environments where organic deposition and anaerobic decay are high, methane may escape to the surface, marsh gas for example.

Figure 10. Maturation of Kerogen Types

Type I
Sapropelic kerogen
(algal)

Type II
Lipid-rich kerogen
(phyto-and zooplankton)

Type III
Humic kerogen
(land plants)

Gas generation | Oil generation

Zone of Catagenesis

As temperature and pressure increase with increasing burial the bacteria are killed off. Around the critical temperature of 60°C oil starts to form from the kerogen as the molecules are cracked. The inner bonds of the kerogen are split and volatile components are lost (paraffin range products). The heavy molecules remain. As the temperature increases with increasing depth of burial these heavy molecules are cracked further producing progressively lighter oils. The cracking of heavy molecules to lighter ones produces water and carbon dioxide, and at higher temperatures hydrogen and methane.

Experiments have shown that significant oil generation occurs between 60°C and 120°C, whilst significant gas generation occurs between 120°C and 225°C. Above 225°C only carbon remains in the form of graphite. Oxygen is lost rapidly during this process due to dehydration and decarboxylation. Carbon and nitrogen are lost least rapidly. Thus the carbon content of the kerogen increases and the H:C ratio decreases with temperature. This thermodynamic transformation of kerogen is known as catagenesis and the sediments are referred to as 'mature'. Measurement of kerogen maturity is obviously necessary for petroleum production potential to be quantified.

Zone of Metagenesis

As stated, liquid hydrocarbons are cracked at high temperatures until a point of 'peak generation' is reached after which production drops off. Initially wet gas is produced. After about 120°C only dry gas is produced. At temperatures above approximately 180°C to 225°C all hydrocarbons are destroyed and the rock itself begins to become metamorphosed. In this zone the sediments are 'post-mature'.

Paleothermometers and the 'Oil Window'

There is a limited temperature/depth range in the Earth within which oil and gas can be generated and preserved (Figure 11). This is called the 'oil window' or 'oil kitchen' and usually occurs at depths of 2500-5000m. The level of maturity appears to increase exponentially with temperature.

Figure 11. Examples of Paleothermometers and the Oil Window (after Selley, 1998).

Figure 12. Kerogen Maturation with Time and Temperature (Connan, 1974).

In the search for petroleum it is necessary to answer questions about the area under exploration such as, are there organic rich rocks present, are they present in viable volumes for production, will they produce oil or gas. In order to begin assessing questions such as these it is also important, as has been mentioned, to measure how mature the hydrocarbon zone is, ie, will it produce petroleum or is it too mature. Measurement of bottom hole temperature will only give readings that are current, and which may bear no resemblance to conditions that the hydrocarbons have been exposed to historically. The use of 'paleothermometers' can determine the maximum temperature range that the rock and hydrocarbons have been subjected to, and thus give an indication of maturity. A wide range of chemical and biological techniques can use for analysis:

1. Chemical paleothermometers:
   • Organic:
     • carbon ratio;
     • electron spin resonance;
     • pyrolysis;
     • gas chromatography.
   • Inorganic:
     • mineral diagenesis;
     • fluid inclusions.
2. Biological paleothermometers:
   • pollen colouration;
   • vitrinite reflectance.

Depending on local conditions, a variety of these techniques may be used during any one exploratory programme.

Hydrocarbon Migration

There are a number of observations that show that the oil and gas we recover commercially today does not generally originate from within the current reservoir rock. It must have therefore migrated from its source.

Depending on circumstances, some or all of the following may be true, thus proving this point:

• organic matter is easily destroyed by oxidation in porous, permeable sediments at the Earth's surface. It must therefore have invaded the reservoir rock after a deeper burial and exposure to higher temperatures;
• hydrocarbons often occur in solution in pores and fractures that must have formed after burial and lithification of the reservoir rock;
• hydrocarbons are generally trapped at the highest point of a permeable rock formation, implying upward and lateral migration;
• oil, gas and water occur stratified within the reservoir in relation to their densities, again implying that they are free to migrate within the rock.

A distinction must be made however between what are termed 'primary' and 'secondary' migration. Primary migration is the migration of the hydrocarbons from the source rock (clay or shale) on compaction, to permeable formations. Secondary migration is the subsequent movement of hydrocarbons within the permeable rocks to form pools.

Primary Migration

Hydrocarbons are generated at great depths where temperatures and pressures are extremely high. The mechanisms behind the expulsion of hydrocarbons from the source rocks are poorly understood, and probably occur via several mechanisms depending on precise conditions.

Questions that need to be answered for an understanding, or at least appreciation, of possible mechanisms include:

1. When did migration occur?
2. What were the physical characteristics of the source rock at that point?, eg, temperature, permeability;
3. What were the chemical characteristics of the source bed at that point?, eg, water and clay composition;
4. What was the nature of the hydrocarbons?, ie, how mature?
5. Did emigration occur in discrete phases or as solutions?

Scientifically many questions are difficult to answer due to the time scales involved and the fact that the processes occur well below the Earth's surface.

Secondary Migration

Secondary migration refers to the movement of the hydrocarbons through the carrier and reservoir rocks. Reservoir rocks differ from compacted source rocks in that they are much more porous and permeable. Once in a reservoir rock, oil, water and gas will separate and travel as distinct phases in the direction of decreasing hydrostatic pressure.

Hydrocarbons will flow with moving fluids through any available permeable pathway until they are obstructed. They move through pore spaces, channels and fractures. A discrete globule of oil will be subjected to a gravity force pulling it down, a buoyancy force pushing it upwards and the capillary force between the grains. In order for the globule to move the buoyancy force must overcome the other forces. Sometimes the capillary force will be greater than the buoyancy force and the hydrocarbon will stop. However, other globules or bubbles will build up and accumulate until the collective buoyancy force is greater than the capillary force and the globule will move.

Upward movement will continue until the hydrocarbons reach the surface as a seepage. In some formations impermeable layers of fine grained rocks (usually shale, salt, fine grained limestones) will form an impenetrable layer (cap rock) and upward migration will cease (Figure 13). The hydrocarbons will continue to migrate laterally until they reach a trapping structure and begin to accumulate, thus forming a pool. Lateral migration will be limited only by the size of the sedimentary basin, sometimes 100 miles or more. However, most petroleum only migrates a short distance.

The resultant pools will be layered with gas at the top, then oil, with water at the bottom. The shape of the pools may be influenced by water flow through the rock (aquifers) as pressure gradients will become tilted. Hydrocarbons will tend to flow laterally in this case. The proportions of hydrocarbons within a pool may also change as continued migration takes place. At a certain point, the reservoir will be at capacity. Once this has occurred any further migration will be accompanied by 'spilling' of denser fluids from the lower sections of the trapping structure. In this way, hydrocarbons may migrate along a series of traps as they spill from one to the next (Figure 14).

Figure 13. Anticlinal Trap and Nomenclature (after Selley, 1998)

Closure
Gas-oil contact | GAS
Oil-water contact | Oil zone
Spill point | WATER
Edge water | Bottom water | Edge water

Figure 14. Lateral Flow of Hydrocarbons due to Spilling (after Gussow, 1968)

(a) Trap I | Trap II | Trap III | Trap IV

Cap rock | Waste

Trap I is filled to the spill point and has a gas cap; only oil is spilling updip into Trap II; Traps III and IV are full of salt water and contain no oil or gas.

(b) Trap I is completely filled with gas, all its oil has been flushed updip into Trap II; oil is now bypassing Trap I; Trap II is filled with oil and is spilling oil updip into III; it still has no gas cap; Trap III has a little oil, while IV is still filled with salt water.

(c) Trap I is unchanged with gas spilling updip into Trap II; oil is bypassing Trap I; Trap II now has a gas cap and is spilling oil updip into Trap III; Trap III is now filled with oil but still has no gas cap; Trap IV is dry.

(d) Solution gas

Migration same as for C, but under different structural relationships; note that height of culmination has no effect on selective trapping elevation of spill point is the controlling feature; height of culmination above spill point determines the maximum pay section; (a solution-gas cap has formed in Trap III).

(e) Migration same as for C; here all culminations are at same elevation; spill points control differential entrapment.

Stages (d) and (e) represent the same stage in migration but under different structural relations.

Key: Gas | Oil | Water