chapter 04 subsurface reservoir trap basin

Petroleum: from organism to trap

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PPPeeetttrrrooollleeeuuummm::: fff rrrooommm ooorrrgggaaannniiisssmmm tttooo ttt rrraaappp Sedimentary organic matter

Definitions and terms The previous section ended with an examination of the molecular composition of petroleum, accompanied with definitions for various molecular components of petroleum. Therefore, before we examine the origin and generation of petroleum it is fitting that we begin by defining many of the terms that will be used throughout this section.

Source rock A petroleum source rock is generally recognized as a fine-grained sedimentary rock that has naturally generated and released enough hydrocarbons to form a commercial accumulation of oil and/or gas (Tissot and Welte, 1984). Implicit in this definition is that a source rock meets the following geochemical requirements (Peters and Cassa, 1994):

• that the source rock contains sufficient quantity of organic matter

• that the organic matter is of sufficient quality to generate oil and/or gas, and

• the source rock attained a level of thermal maturity capable of generating and expelling hydrocarbons

The term potential source rock describes an organic-rich fine-grained sedimentary rock that is not sufficiently mature to generate petroleum (i.e., oil), but under the right conditions could generate petroleum.

Kerogen Although not specifically mentioned in the definition of a source rock given above, the existence of kerogen is an implicit key characteristic of all source rocks. Kerogen is generally defined as sedimentary organic matter that is insoluble in common organic solvents and aqueous alkaline solvents (Tissot and Welt, 1984). On this basis, kerogen is rendered distinct from humic (organic) matter within soil because humin is soluble in aqueous alkaline solvents. Kerogen is distinguished from petroleum because common organic solvents are used to extract bitumen and oil from rock! The organic matter that is kerogen is commonly a mixture of different types of organic matter, the composition of which is largely dependent upon the composition of the original biologic precursor.

Macerals The term maceral was originally coined to describe the microscopic constituents of coal, that are recognizable under a microscope (Stopes, 1935), but has since been broadened to include all recognizable organic matter in sedimentary rocks (Figure 18). Generally, macerals represent the organic remnants of plant or animal matter and readily distinguishable by differences in morphology, various optical properties and technological property (Bend, 1992; Taylor et al., 1998). Although macerals can be broadly distinguished by differences in chemistry and, or technological property, maceral identification and name designation is best achieved using a reflected light microscope (Figure 18).

Figure 18. Examples of macerals. (a and b) The macerals Alginite (A) and Fluorinite (F) are both autofluorescent under u.v. light. In these images Alginite (A) appears yellow to yellow-green, whereas the Fluorinite (F) appears a dull red-brown. (c) Under reflected white light, the med-grey maceral Telinite (T) has retained much of the original texture of the original plant material. Telinite (T) is in-filled by a darker-grey maceral known as Collinite (C). Images (a) and (b) are in reflected autofluorescent light and (c) in reflected white light.


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The production and accumulation of organic matter

The carbon cycle The creation of a fossil fuel begins with the creation and accumulation of organic matter at the earth’s surface. Organic matter is defined as “material comprised solely of organic molecules in monomeric or polymeric form, that are derived directly or indirectly from the organic part of organisms... deposited or preserved in sediments” (Tissot and Welte, 1984; p3). The production of organic matter starts with photosynthesis, with sunlight of course being the primary source of energy. The primary producers, such as photosynthetic bacteria and blue-green bacteria, are known as phototrophs because they use light (energy) to produce glucose.

h.v (energy)

6CO2 + 12H2O C6H12O6 + 6O2 + 6H2O

(674 kcal) An equation for photosynthesis. Please note that oxygen is a by-product.

Phototrophic organisms are found on land or in the euphotic zone of the water column. Organisms that utilize carbon dioxide as their sole source of carbon are autotrophs, whereas those that derive their carbon from existing organic structures are known as heterotrophs, this is the basis of the food pyramid. Welt (1970) estimated that the total amount of organic carbon produced within the biosphere is 6.4 x 1015 t. In contrast the global preservation of organic carbon within sediments is less than 0.1% of all organic carbon production. Therefore, the bulk of all organic carbon produced is either bound within inorganic sediments or recycled within the biosphere as carbon dioxide. Some carbon dioxide does escape from the major cycle (Figure 19) into isolated environments, but of all the organic carbon produced, approximately 0.1 to 0.01% becomes fossil fuel, which is indicated as a ‘leakage’ in Figure 19.

Production There are two main factors that govern the creation and accumulation of organic matter in sediments (Demaison and Moore, 1980). They are the production of organic matter and organic matter preservation. Both are of equal importance, because both influence the amount of organic matter that occurs within a given potential source rock. However, without production, preservation becomes moot! Biological activity within an aquatic environment (e.g. marine) is mainly controlled by sunlight, temperature and the availability of nutrients, such as nitrates and phosphates. Therefore, the greatest level of biological production is concentrated in the upper 60 to 80 m of the water column, which is known as the euphotic zone. The productivity of organic carbon (C org.) within coastal water, which averages approximately 100g C org ma-1, is about twice that of the open ocean (Tissot and Welt, 1984; Hunt 1996). Continental margins that experience the phenomenon of up-welling (e.g. western South America) are especially productive, generating 300 g C org ma-1. However, most of the primary organic matter is either lost to the food chain or lost during sedimentation. The preservation of organic matter, therefore, plays a key role in the creation of a source rock.

Figure 19. A simplified organic carbon cycle (after Welte, 1970; Tissot and Welte, 1984; Hunt, 1996 and others).


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Preservation Approximately 80% of all primary organic matter presently produced in the ocean is consumed (Menzel, 1974). The most effective consumers are zooplankton and aerobic microorganisms. It therefore follows, that the duration of time a given particle of organic matter spends suspended within oxygen-rich water has a direct impact upon the successful accumulation of organic matter within sediment. The preservation potential of organic matter can be enhanced by the adsorption of organic matter onto the surface of mineral particles, which effectively increases the mass of the organic matter, enabling it to sink faster. However, the most effective means of attaining preservation is to decrease the amount of oxygen within the water column, or at the water/sediment interface. Depositional settings generally considered favorable for the production and preservation of organic matter are those in which bottom waters contain very little dissolved oxygen (Demaison and Moore, 1980). Such depositional environments are considered by Tyson and Pearson (1991) to include dysoxic (2.0 to 0.2 ml oxygen per liter water), suboxic (0.2 to 0.0 ml oxygen per liter water) and anoxic (0.0 ml oxygen per liter water). Within an oxygen-rich environment (>2.0 ml oxygen per liter water) aerobic bacteria utilize oxygen to degrade organic matter and generate the by-products carbon dioxide and water. In contrast, within an anoxic environment, anaerobic bacteria must acquire oxygen via a sulfate reduction process, which is a relatively slower process. Therefore, aerobic bacteria are much more efficient at consuming organic matter than their anaerobic counterparts, although it is important to note that the removal of organic matter does not cease under anoxic conditions, but occurs at a significantly slower rate; a rate that favors the preservation, rather than removal of organic matter (Figure 20).

There are a number of reasons why anoxia may occur within the water column or sediment. The most common cause of anoxia is a respiratory demand for oxygen that is greater than the available amount of dissolved oxygen. In an open marine environment oxygen is constantly replenished, however, situations can arise that restrict the vertical exchange of water and promote the creation of anoxia (Figure 21). For example, within Lake Tanganyika, East Africa, the presence of a thermocline prevents the vertical mixing of water and the promotion of anoxic conditions at depth. Therefore, sediment deposited under anoxic conditions is associated with relatively higher organic matter content. The presence of sill at the entrance of the Black Sea (i.e., Bosporous, Figure 21) restricts the exchange of water, promoting the development of a halocline and anoxic conditions at depth (Demaison and Moore, 1980).

Figure 21. Two contemporary basins that are considered to be examples of an anoxic depositional setting. The water in Lake Tanganyika is stratified because of a permanent thermocline, whereas limited water exchange over a shallow sill has promoted the development of a permanent halocline in the Black Sea. The existence of a thermocline or halocline promotes anoxia within the water column (after Demaison and Moore, 1980).

Figure 20. The preservation potential of organic matter as related to the presence of oxic or anoxic bottom water conditions. In the presence of free iron the sulfate reduction process will promote the formation of pyrite, whereas in the absence of iron, hydrogen sulfide is produced (after Demaison and Moore, 1980).


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The sedimentary environment and organic matter

Sediment permeability The mineralogy of the host sediment can also influence the preservation potential of organic matter (Figure 22). Clay sized particles can adsorb organic matter (onto their surfaces) and are more readily coated with organic matter than coarse grained siliciclastics. Also clay particles are often transported further and deposited in low energy environments. In contrast, sands are deposited in higher-energy environments; environments that are often associated with the presence of oxygenated water, higher sedimentation rates and an abundance of aerobic micro-and macro-biota. The presence of any, or all, of these characteristics will conspire against the deposition and preservation of organic matter. Sediment particle size is also important because the relative decrease in permeability associated with clay-sized particles restricts the exchange of oxygen-depleted water by oxygen-rich water (Figure 22). Whereas, the higher porosity and permeability of recently deposited sands enables oxygen rich waters to permeate the upper few meters of sediment, thereby promoting the removal of organic matter by scavenging metazoan (Figure 22). The existence of fine laminae within a fine-grained sedimentary rock is generally attributed to the presence anoxia within the depositional environment and the absence of bioturbation (Raiswell and Berner, 1985).

Carbonate rocks Carbonate rocks are interesting in that they can be both source and reservoir. Although bioherm and reef carbonates often make good reservoir rocks they generally have diminished potential as source rocks because of the high rate of scavenging within those environments. The most favorable depositional environment for the creation of a carbonate source rock include environments that favor: • the formation of a halocline (water stratification) and anoxic conditions at depth • the growth of algal-rich sediments

Argillaceous rocks Rocks predominantly comprised of clay minerals, i.e. claystone, mudstone and shale are argillaceous. However, as discussed above, not all argillaceous rocks have source potential, generally clay deposited under anoxic conditions possess the greatest potential (Figure 23). Argillaceous rocks that have the highest organic carbon content and the greatest generating potential may:

• be very finely laminated due to the absence of bioturbation • contain pyrite (or some other sulfide) • be micro-fractured (possibly due to over pressuring) • have a high trace element/metal content (e.g., Mg2+, U4+, etc.,) • contain the remnants of micro- and macro-biota (as either

kerogen or skeletal remains) • be black to dark brown or dark gray, although Paleozoic

source rocks typically deviate from this generalization.

Figure 22. Preservation potential due to lithology. A comparison between an argillite (top) and ‘sand’ (bottom). Oxygenated water can penetrate the more open pore network of the sand promoting the removal of organic matter (Tissot and Welte, 1984; with kind permission of Springer Science and Business Media).

Figure 23. An example of shale (cut perpendicular to bedding) in reflected white light. A ‘vitrinite particle’ is indicated V, a wisp of kerogen K and a trail of generated hydrocarbons emanating from the kerogen is indicated by H. Width of image 250 microns.


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The chemical composition of organic matter

The biological precursor The distribution of organic matter is not capricious. Living species form natural associations that reflect the habitat of a given environment. For example, the type of species that typify a fresh-water, terrestrially-bound lake is markedly different from those that are found in a coastal marine setting. Therefore, the type of organic matter within a potential source rock will vary according to depositional setting and the type of species that occur within that environment. The natural association of species within given environment gives rise to the concept of organic facies (Rogers, 1980; Jones, 1984). But before we examine the significance of organic facies we need to examine the composition of organic matter.

Organic matter consists of various groups of molecular constituents: i.e. proteins, carbohydrates, lipids and (in higher plants) lignin. However, significant differences in the relative proportion of each molecular group1 exist for various types of organic matter. For example, note the variation in protein content between terrestrial plants, such as Spruce wood and Scots pine, and marine zooplankton (Table 3). Similarly, the terrestrially derived examples contain lignin, which is absent in the other three examples.

Therefore, the chemical composition of organic matter within a source rock is determined by the type and variation of living precursor within a given depositional environment; which in turn are dependent upon a number of environmental factors. Living organisms within the marine realm are affected by light, temperature, the availability of nutrients and oxygen, and the presence of land barriers; whereas terrestrial habitats are influenced by climate, the type and availability of nutrients, and the availability oxygen (Tissot and Welte, 1984). The factor of geological time is also relevant, due to the evolutionary development of species. Source rocks of the Lower Paleozoic (e.g., Cambrian and Ordovician), are typically devoid of organic matter derived from higher plants, since the diversification of vascular plants did not occur until the Devonian (Thomas and Spicer, 1986). For example, the kukersites of Upper Ordovician age (Figure 24) within Estonia and North America (Hutton, 1987; Fowler and Douglas, 1984; Douglas et al., 1991) are dominated by the blue-green alga Gloeocapsomorpha prisca (Zalesky, 1917). Because these source rocks are of Upper Ordovician age they do not contain terrestrially derived material, such as spores, or the macerals cutinite and resinite, or macerals from the vitrinite group.

1 Proteins are highly ordered polymers, made from individual amino acids and account for most of the N2 within an

organism. They can be broken down, either by enzymes or hydrolyzed. Carbohydrates have a generalized formula of Cn(H2O)n and are essentially the hydrated forms of carbon (e.g. cellulose, chitin,

and mono-, and poly-saccharide). Higher plants contain high amounts of cellulose whereas algae and marine organisms are devoid of cellulose.

Lipids are water insoluble and include waxes, plant or animal oil and fats, oil-soluble pigments, terpenoids, and steroids. With respect to the formation of hydrocarbons, lipids are the most important group.

Lignin (and tannin) are complex 3D aromatic molecules that give plants structural rigidity.

Figure 24. Kukersite of U. Ordovician age from the Williston Basin, Saskatchewan, Canada, containing G. prisca (G).

Table 3. The composition of living matter (examples) (data from Hunt, 1996)

Organic matter type Molecular group1

Proteins Carbohydrates Lipids Lignin

(wt. % ) (wt. % ) (wt. % ) (wt. % )

Spruce wood 1 66 4 29 Scots-pine needles 8 47 28 17 Phytoplankton 23 66 11 0 Diatoms 29 63 8 0 Zooplankton 60 22 18 0


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Kerogen Type

Introduction Because sedimentary organic matter can and will vary in amount and type from place to place for reasons previously outlined, geoscientists need a classification scheme that differentiates between various types of sedimentary organic matter, better known as kerogen. A hypothetical example was given in the previous section that contrasted the petroleum generative potential of a terrestrially derived kerogen against a marine sourced kerogen. It was speculated, in that example, that the terrestrially derived kerogen would contain molecular remnants and modified material derived from lignin, cellulose and other carbohydrates, and minor amounts of lipid material (i.e., relatively low hydrogen content); whereas the marine sourced kerogen would contain molecular remnants and modified material derived from lipids, carbohydrate and proteins (i.e., relatively higher hydrogen content). We also reviewed earlier (Chapter 2) that petroleum, like kerogen is predominantly comprised of organic compounds containing principally the elements hydrogen, carbon and oxygen. With respect to the generation of petroleum, the most fundamental characteristic of kerogen is hydrogen content, because under optimal conditions a hydrogen-rich kerogen will generate more oil than a hydrogen-lean kerogen. Therefore, by determining the elemental composition of kerogen it is possible to differentiate and classify kerogen, and broadly predict the type of petroleum a given kerogen will generate in the subsurface under the right conditions.

Atomic ratio method The van Krevelen diagram is an x-y cross-plot of the Atomic Ratio of the elements Hydrogen/Carbon (H/C) against the Atomic Ratio of Oxygen/Carbon (O/C) obtained by elemental analysis (Figure 25). For example, the bulk analysis of a hypothetical marine-sourced kerogen may contains carbon (76.4 wt. %), hydrogen (8.3 wt. %) and oxygen (13.1 wt. %), which gives H/C and O/C Atomic Ratios of 1.3 and 0.13 respectively. Our hypothetical marine-sourced kerogen plots as an immature Type II on the diagram. In contrast, our hypothetical terrestrial kerogen contains carbon (72.7 wt. %), hydrogen (6.0 wt. %) and oxygen (19.0 wt. %) which gives H/C and O/C Atomic Ratios of 0.9 and 0.2 respectively and plots as an immature Type III kerogen .

Hydrogen or Oxygen Index Probably the most common means of characterizing kerogen is via bulk pyrolysis, which is typically obtained by RockEval pyrolysis. Part of the appeal of this approach is convenience and the wealth of data obtained during analysis. Data is derived by pyrolyzing the kerogen under standardized conditions (Espitalie et al., 1980 etc.) and yields data that can be plotted in an analogous way to the van Krevelen type diagram. The Hydrogen/Oxygen Index cross-plot (Figure 26) also designates kerogen into one of three main petroleum generative kerogen Types. A fourth kerogen Type also exists (Type IV) but is generally considered non-generative. Continuing to use our hypothetical example kerogen, the immature marine example may generate a Hydrogen Index of 620 mg HC/g TOC and an Oxygen Index of 75 mg CO2/ g TOC (i.e., Type II kerogen). In contrast, the terrestrial kerogen may generate a Hydrogen Index of 110 mg HC/g TOC and an Oxygen Index of 125 mg CO2/ g TOC (i.e., Type III kerogen).

Figure 25. A cross-plot of the atomic ratios H/C versus O/C, generally known as a ‘van Krevelen diagram’, showing the broad evolutionary paths for Types I, II and III kerogen and the empirically determined three areas of thermal maturity known as diagenesis, catagenesis and metagenesis (after van Krevelen, 1960; Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; and others).

Figure 26. The Hydrogen and Oxygen Index cross-plot, showing the evolutionary paths for Type I, II, III and IV kerogen (after Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; and others).


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Type I kerogen Kerogen of this type has the highest hydrogen content of all kerogen types and is strongly oil prone. Type I kerogen is derived from organic matter rich in lipids and is generally subdivided into Alginite A, representing the accumulation of algal material, e.g. Tasmanites, Gloeocapsomorpha prisca, Botryococcus or Pila (Figure 27), or Alginite B, hydrogen-rich amorphous organic matter (Figure 27c). The G. prisca-rich Ordovician kukersites of North America represent an example of Type I kerogen.

Characteristics van Krevelen diagram: a high initial H/C (e.g., 1.3+) and a low O/C (i.e., less than 0.1) Atomic Ratio. HI/OI plot: a very high Hydrogen Index (600 to 900) and very low Oxygen Index (10 to 30).

Type II kerogen This is perhaps the most commonly reported type of kerogen, which is probably a chemical averaging artifact due to the bulk analysis of complex kerogen mixtures within a given source rock. True Type II kerogens possess relatively high initial hydrogen content and a moderate amount of oxygen (Figure 28). Examples of Type II kerogen include marine organic matter, phytoplankton, zooplankton and bacteria deposited in a reducing environment, and some terrestrially derived material also (Figure 28b and c), although marine derived Type II kerogen is more common. Typically Type II kerogen is associated with a lower oil yield than an equivalent volume of Type I kerogen. The Jurassic Kimmeridge clay (North Sea basin) contains a prolific Type II kerogen. Type II kerogens may also be subdivided on the basis of sulfur content (Hunt, 1996).

Characteristics van Krevelen diagram: a moderately high initial H/C (1.0 to 1.3) and a moderate O/C (0.03 to 0.15) Atomic Ratio. HI/OI plot: a high Hydrogen Index (550 to 600) and moderate Oxygen Index (50 to 100).

Type III kerogen This kerogen type releases little in the way of aliphatic material during thermal maturation and, therefore, true Type III kerogens are not usually considered oil prone. Type III kerogens are typically derived from terrestrially derived vascular plant material, i.e., vitrinitic, not liptinitic (Figure 29 a and b). The Manville shale (USA and Canada) is an example of a Type III kerogen.

Figure 27. Examples of Type I Kerogen known as Alginite. Image (a) contains Pila (P); image (b) contains Tasmanites (T), and image (c) contains amorphous organic matter (A). All images in reflected autofluorescent light (image 27c courtesy of L. Stasiuk).

Figure 28. Examples of Type II Kerogen. Image (a) contains the maceral Sporinite (S);images (b) and (c) contain the macerals Resinite (R) and Cutinite.


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Characteristics Van Krevelen diagram: a low H/C Atomic Ratio (i.e., less than 1.0) and an initial O/C ratio between 0.2 to 0.3. HI/OI plot: a low initial Hydrogen Index (i.e., less than 150) and an high initial Oxygen Index (e.g., 150+).

Type IV and residue Some recognize a fourth type of kerogen, known as Type IV. However, the oil and gas generation potential of this kerogen is extremely low and typically considered non-generative. An example of this type of kerogen is the maceral Fusinite, which is derived by the oxidation of derived vascular plant material (Figure 29c)

Organic facies As stated earlier, the chemical composition of organic matter within a source rock is determined by the type and variation of living precursor within a depositional environment; that is dependent, in turn, upon a number of environmental factors. Living organisms within the marine realm are affected by light, temperature, the availability of nutrients and oxygen, and the presence of land barriers, whereas terrestrial habitats are influenced by climate, the type and availability of nutrients, and the availability of oxygen (Tissot and Welte, 1984). Furthermore, since the early Devonian, the diversity and number of species has increased, giving rise to natural associations of increasing differentiation and complexity due to variations in depositional setting (Figure 30) and evolution. Therefore, the chemical composition of a given kerogen is largely dependent upon depositional environment and the natural association of plant and/or animal species present within that environment (Figure 30). This in turn influences the generative potential of the kerogen (i.e., gas prone or oil prone). For example, a marine source rock may contain organic matter principally derived from marine plankton, composed of proteins, carbohydrates and lipids. In contrast, a terrestrially-derived source rock may contain organic matter derived from vascular plants, mainly composed of lignin, carbohydrates and some lipid material. It would be reasonable to anticipate (following this example), that the marine-derived kerogen would be oil prone, whereas the terrestrially-derived kerogen would probably be gas prone.

Lateral and vertical variations in association of organic matter are increasingly described and interpreted in terms of organic facies (Rogers, 1980; Jones and Demaison, 1982; Jones, 1984, 1987; Jacobsen, 1991). Organic facies are determined by the type of organic matter within the rock unit, which is generally considered linked to the paleodepositional environment (Figure 31) (Rogers, 1980). Jones (1984) defines an organic facie as a mapable subdivision of a designated stratigraphic unit, distinguished from the adjacent subdivisions on the basis of the character of its organic constituents, without regard to the inorganic

(a) (b) (c)

Figure 30. A section through the Earth's crust showing possible generalrelationships between depositional setting, available oxygen supply and broaddifferences in organic matter type (marine/terrestrial/algal).

Figure 29. Examples of Type III and Type IV kerogen. Image (a) Type III kerogen-bearing shale (K); image (b) is a Vitrinite-rich sediment (V), and image (c) contains Fusinite (F) as an example of a Type IV kerogen. (image 29c courtesy of L. Stasiuk).


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aspects of the sediments. Tyson (1995) notes that this definition does not limit the definition to any given technique or methodology. This is significant since organic matter within sediment can be characterized by microscopy, by geochemical analysis or better still by integrating the two. The organic facies concept can be used as an exploration tool by the petroleum geochemist to map source rock characteristics and also to predict the occurrence, quality and generative potential of source material within a basin or stratigraphic sequence. For a detailed account of organic facies please refer to Tyson (1995).

The generation of petroleum

Thermal maturation Thermal maturation is the natural transformation of kerogen into petroleum in response to increased thermal stress, which is due to an increase in burial depth over geological time. The maturation threshold for each kerogen type differs because the transformation of kerogen into petroleum involves the thermal rupture of chemical bonds, and is dependent upon the molecular make-up of a given kerogen. Due to differences in (bond) dissociation energy, in which carbon-sulfur and carbon-oxygen bonds generally have lower dissociation energies than carbon-hydrogen bonds (Hunt, 1996). Following deposition and preservation the subsequent transformation of organic matter into kerogen and the generation of petroleum involves three discrete,

Figure 31. The relationship between selected organic facies and sedimentary environment and climate, according to Jones (1987). A listing of Organic facies (i.e., D, C, B etc.) and a summary of respective characteristics is given below in Table 4; (in Tyson 1995, courtesy of Springer Science and Business Media).

Figure 32. The three stages of kerogen transformation, with the relative production of biogenic gas, oil and thermogenic gas. Within the nine inset figures, inherited hydrocarbons are indicated in solid black, whereas generated hydrocarbons are in gray (Tissot and Welte, 1984; with kind permission of Springer Science and Business Media).

Table 4. Organic facies and selected characteristics (after Jones, 1984, 1987; Jones and Demaison, 1982; Tyson, 1995).

Organic H/C Atomic Ratio Pyrolysis yield Generation facies at %Ro ~ 0.5 HI OI potential Dominant organic matter Sedimentary structure

A > 1.45 > 850 10 to 30 oil Algal; amorphous AB 1.35 to 1.45 650 to 850 20 to 30 Amorphous; minor terrestrial Laminated B 1.15 to 1.35 400 to 650 30 to 80 Amorphous; commonly terrestrial Well bedded to laminated BC 0.95 to 1.15 250 to 400 40 to 80 mixed Mixed; some oxidation Poorly bedded C 0.75 to 0.95 125 to 250 50 to 150 mixed Terrestrial; some oxidation Poorly bedded to bioturbated CD 0.60 to 0.75 50 to 125 40 to 150+ gas Oxidized; reworked D < 0.6 < 50 20 to 200+ none Highly oxidized; reworked Massive, bioturbated


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sequential, stages of alteration (Figure 32) known as: diagenesis, catagenesis and metagenesis (Espitalie et al., 1980; Tissot and Welte, 1984). Each stage of alteration is characterized by a different process. The diagenetic stage is predominantly biochemical, within which microbial processes predominate. Catagenesis immediately follows diagenesis and represents the principal stage of petroleum generation. When kerogen crosses the chemical boundary (a.k.a. threshold) between diagenesis and catagenesis, thereby entering the catagenesis stage, the kerogen is said to be thermally mature with respect to petroleum generation. The final stage, known as metagenesis, is typically associated with the generation of dry gas and non-hydrocarbon gases.

Diagenesis Diagenesis (Figures 32 and 33) is the immature stage and typically associated with the progressive biochemical transformation of organic matter into kerogen. Diagenesis commences within the water column and continues within the subsurface until a temperature threshold of 50 to 75° C, or a vitrinite reflectance minimum of Ṝom 0.5% is reached2. It is within the diagenetic stage that the crucial process of preservation occurs. Some hydrocarbons may co-exist with the immature kerogen (Figure 32), however, they are either inherited hydrocarbons from biological organisms (e.g., biomarkers), or metabolic by-products (e.g., biogenic methane); shown in black within the nine inset diagrams in Figure 32. Examples of inherited hydrocarbons include the tricyclic and pentacyclic biomarkers, terpenoids, certain isoprenoids and waxes. Typically, the generation of petroleum, via the thermal rupture of chemical bonds, is not considered a characteristic of diagenesis. However, bitumen and heavy oil generation is known to occur in carbonate-rich, sulfur-bearing kerogen, such as Type IIS (Horsfield and Rullkötter, 1994; Hunt, 1996) because of differences in bond dissociation energy (Hunt, 1996).

Catagenesis The onset of petroleum generation and the thermal degradation of kerogen marks the beginning of catagenesis (Figures 32 and 33). The generation of petroleum is indicated by a significant decrease in atomic H/C (e.g. 1.25 to 0.5 in Type II) due to a net loss of hydrogen from the kerogen. This process can be effectively depicted on a van Krevelen diagram (Figure 33) with data derived from the elemental analysis or Rock Eval pyrolysis of kerogen. Despite the apparent synonymous nature of catagenesis and the ‘oil window’, catagenesis is widely recognized as having both an oil generating and wet gas-generating zone, in that order depending upon the kerogen Type. The oil window is defined as that part of catagenesis in which oil generation exceeds gas generation, whereas wet gas formation is associated with diminished oil generation. Vassoevich (1969) described the petroleum generation process during catagenesis as having a principle zone of oil generation, now simply known as the oil window (Figures 33 and 34), the boundaries of which are routinely defined by using techniques such as vitrinite reflectance or RockEval pyrolysis. However, because of differences in activation energy, the ‘oil window’ varies for different kerogen Types. For example, it is lowest (Ṝom 0.5% and a Tmax 430oC) for Type IIS kerogen and highest for a Type I kerogen (~ Ṝom 0.65% and a Tmax 440oC) due to differences in the presence of different elements. Throughout catagenesis, kerogen becomes increasingly aromatic and greatly depleted in paraffinic/naphthenic compounds (Figure 34; numbers 2 to 4) due to the process of oil/gas generation. This progressive increase in aromaticity creates changes within the kerogen (e.g. increase in light opacity, red-shift in autofluorescence; see Figure 34) that form the basis of many indices of maturation (e.g., Heroux et al., 1979) as used by organic petrographers and petroleum geochemists.

2 The vitrinite reflectance parameter %Ṝom indicates that the vitrinite reflectance value represents the arithmetic mean (Ṝ) of a number of values

measured using oil immersion (o) and non-polarized light (m) under standardized conditions.

Figure 33. The thermal evolution of kerogen as depicted on a van Krevelen type diagram. Note the color-coded kerogen maturity zones diagenesis, catagenesis and metagenesis for each kerogen Type. Each recognized kerogen Type has an evolutionary tract, along which kerogen of similar composition but of increased level of thermal maturity plot. The attained level of thermal maturity is determined by analyzing the residual amount of elemental hydrogen, oxygen and carbon within a sample of kerogen and calculating the appropriate atomic ratios (after van Krevelen (1960), Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984 and others).


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Metagenesis This zone represents the thermal cracking of previously generated hydrocarbons, should any remain within the source rock (Figure 33) and the additional generation of methane (C1) directly from the remaining kerogen. Metagenesis is considered to be the final stage in the generation of oil and gas, and is simply a process of organic metamorphism due to the relatively higher temperatures that typically occur deep within a basin. During metagenesis, oil is thermally cracked to produce dry gas (methane) and a carbonaceous, aromatic-rich residue (Figure 34; number 5).

Figure 34. Changes in composition and appearance in response to thermal maturation, using Type II kerogen as an example. Five infrared spectra, representing changes in a Type II kerogen during thermal maturation (shown on the left) are stacked to show the relative changes in molecular structure due to the process of thermal maturation. A series of spore ‘palynomorphs’ exhibiting the sequential changes in opacity are also shown, alongside the corresponding level of thermal maturity. On the right, a van Krevelen diagram shows the approximate equivalent of thermal maturity as determined by the atomic ratios of H/C and O/C. This example is for illustrative purposes only (stacked infra-red spectra modified from Tissot and Welte, 1984, with kind permission of Springer Science and Business Media; spore micrographs modified from Combaz, 1980, courtesy of Editions Technip; van Krevelen diagram modified after van Krevelen (1960), Tissot et al.,1974; Durand, 1980; Tissot and Welte, 1984 and others). Note within each of the stacked infra-red spectra, the area and height of each peak corresponds to the abundance of a given molecular group (e.g. C=O). Note that changes in kerogen chemistry (i.e. decrease in oxygen functional groups, aliphatic C-H, and an increase in aromatic C-H) due to thermal maturation are accompanied with changes in spore opacity due to an increase in the adsorption index. The changes in molecular group and changes in spore opacity are reflected by successive differences in the atomic ratios H/C and O/C.

Note specifically: #1: Recent organic matter that is thermally immature (diagenesis). Note the high C=O peak, high aliphatic peaks and very low aromatic peaks.

Correspondingly this immature kerogen has a relatively high H/C and moderately high O/C Atomic Ratio. Spores are clear to pale yellow.

#2: Onset of catagenesis: entering the ‘oil window’ [marginally mature]. Note the decrease in C=O and aliphatic compounds, loss of H and O relative to C in the Atomic Ratio and a darkening of the spore.

#3: Peak of hydrocarbons generation [mature], catagenesis. Continued decrease in C=O and aliphatic compounds with a significant increase in aromatic content, marked loss of H relative to C in the Atomic Ratio and a further darkening of the spore to a dark orange color.

#4: End of hydrocarbon generation [post mature] and start of metagenesis. C=O and aliphatic compounds are markedly reduced with an accompanying increase in aromatic content. Note also the continued loss of H relative to C in the Atomic Ratio and a further darkening of the spore to a dark brown.

#5: Metagenesis. The aliphatic content is significantly reduced whereas the aromatic content has increased. The H/C and O/C Ratios are greatly diminished and the spore is black.


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Source rock assessment There are many techniques available to determine the thermal maturity of a potential source rock, some are standardized by scientific organizations (e.g., The Society for Organic Petrology or the International Committee for Coal Petrology), and some are not. Without doubt, the two most universally accepted techniques used by industry include RockEval pyrolysis (Tmax) and vitrinite reflectance (%Ṝ om). Vitrinite reflectance measures the amount of light reflected from the surface of a polished fragment of vitrinite (i.e., Type III kerogen), whereas RockEval pyrolysis indirectly derives the hydrogen, carbon and oxygen content of kerogen from a crushed sample plus a host of other useful parameters (e.g., Tmax, PI etc). Neither technique is without flaw, since both have well known limitations. However, they permit the rapid determination of thermal maturity for a given sample and provide a suitable framework by which other techniques can be compared. For example, by reference to specific values, such as Ṝom 0.5 to 0.6% and Tmax values of 430o to 435o, the boundary for the onset of oil generation can be rapidly determined, easily defined, and universally understood.

Migration and Accumulation of Petroleum Introduction

Definitions The economic accumulation of petroleum generally occurs in a relatively coarse-grained porous and permeable rock that contains little or no insoluble organic matter (i.e. kerogen). It is, therefore highly probable that petroleum compounds underwent some form of migration phenomenon from their place of origin to place of accumulation. The release of petroleum compounds from kerogen and their subsequent movement within the fabric of the source rock has been termed primary migration. Secondary migration is the movement of petroleum from the source rock, through the larger pore-throats of more permeable beds or permeability conduits, to the trap. Tertiary migration is the movement of petroleum from a previous accumulation to either the earth’s surface or a shallower trap.

Compaction Sediment compaction creates an increase in bulk density, a marked reduction in porosity and changes in pore geometry. The rate at which compaction occurs is largely governed by the properties of the sediment, the process of mineral diagenesis, the rate of fluid expulsion, rate of deposition and burial depth. Within shale in particular, the greatest decrease in porosity occurs at relatively shallow depth, with a rate that generally decreases with increasing depth; accompanied by a marked decrease in average pore diameter, with final values of between 1.0 to 2.5 Nm (Figure 35). Hall et al., (1986) reported porosities of 5.2% for the Cherokee Shale (Oklahoma) and 4.3% for the Bakken Formation (N. Dakota). Both are proven source rocks. The reported median pore diameters were 7.0 nm and 5.0 nm respectively. However, the laboratory derived values of Hall et al., (1986) would probably be reduced by the presence of chemi- or physi-sorbed water and the presence of structured water. Such values may then be closer to the median value of 3 nm proposed by Momper (1978). The effective diameter of petroleum molecules varies greatly and generally increases with increasing molecular weight, as shown in Figure 35 and Table 5 (Welte, 1972; Hunt, 1979, 1986; Tissot and Welte, 1984). When compared to the ‘average’ shale pore diameter most complex molecules are either similar in size or larger. So how does the oil or gas get out of the source rock?

Figure 35. Generalized relationship between depth, temperature, pressure and porosity (modified after Tissot and Welte, 1984), with kind permission of Springer Science and Business Media.


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Primary migration

Chemical and physical constraints A number of mechanisms have been proposed for the process of primary migration, including petroleum moving as discrete molecular entities, as a continuous oil or gas phase, as individual oil droplets or gas bubbles (globules), as colloidal and micelle solutions, or as true molecular solutions! Theoretically, primary migration could involve a variety of mechanisms. In reality petroleum generation causes migration. The mechanism of primary migration is not yet unequivocally known but generally considered to occur via processes involving diffusion, solution and/or hydraulic pressure.

Diffusion A diffusional process is one in which molecules move from high concentration to lower concentration. Diffusion preferentially favors the smallest molecules, such as methane (Table 5) compared to other gaseous hydrocarbons (Welt, 1972; Magoon and Claypool, 1983; Krooss and Leythaeuser, 1997).

Solution Benzene and toluene are highly soluble in water3 (Price, 1973, 1976; McAuliffe, 1966). In contrast methane is relatively insoluble in fresh water at low temperature and pressure (McAuliffe, 1966), although at higher temperature and pressure a solubility increases of 300 times was reported at 6,096 m (20,000 feet) (Culberson and McKetta, 1951). Generally, the solubility of petroleum compounds decreases in the order: aromatics cycloalkanes normal alkanes, although the majority of petroleum compounds have solubilities in water that is less than 1.0 mg liter (McAuliffe, 1966) at 25 °C. Most economic accumulations of petroleum consist of compounds that are insoluble in water.

Hydrocarbon Phase Migration The pressure-driven, hydrocarbon-phase movement of petroleum is shown in Figure 36 (Ungerer et al., 1983). A source rock containing organic carbon (4.0 wt. %) is equal to 9.8% organic matter by volume. At depths greater than 1,500 m the organic matter would occupy a significant proportion of available pore space. A source rock containing more than 4% Corg would become ‘oil wet’ (with an associated high resistivity). The presence of networks of both bitumen and oil increases the oil wettability of shale, possibly facilitating oil-phase migration (Hunt, 1996). During the transformation of solid kerogen into liquid hydrocarbons, or gas, there is an increase in fluid pressure (i.e. pore pressure) (Momper, 1978; Ungerer et al., 1983). The combined effects of oil generation, the thermal expansion of connate water, rapid burial, and partial transfer of geostatic stress from rock fabric to pore fluid are thought to generate pressure centers within the source rock; which induces micro-fracturing, along which migrating hydrocarbons are expelled (Figure 36). This pressure driven mechanism of primary migration is thought to involve many, repeat cycles:-

pressure build-up microfracturing hydrocarbon expulsion pressure release oil generation expansion (repeated many times)

3 Price (1973, 1976) and McAuliffe (1966) report solubilites of 1,740 ppm (+17) and 1,780 ppm (+45) respectively for benzene, and 554 ppm (+15)

and 515 ppm (+17) respectively for toluene at 25° C

Table 5. Effective diameter of selected molecules

Molecule Effective diameter (Nm) Water ~0.32 Carbon dioxide 0.33 Methane 0.38 Pentane 0.46 Benzene 0.47 n-alkanes 0.48 Cyclo-hexane 0.54 Complex ring structures 1.00 to 3.00 Asphaltene molecules 5.00 to 10.00

Source: Stewart (1928), Welte (1972), Hunt (1979, 1986), Tissot and Welte (1984)

Figure 36. Microfracture induced hydrocarbon phase migration during oil generation. (A) Represents the initial stage prior to oil generation, in which the bulk of the source rock is water-wet. (B) Oil generation has occurred with the creation of an oil-wet pore network around the kerogen. The generation of oil creates an increase pore pressure that either opens existing fractures or creates new ones. The oil is then expelled along oil-wet microfractures (modified and redrawn from Ungerer et al.,1983)


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Secondary Migration Secondary migration is defined as the movement of petroleum through more permeable and porous carrier beds and reservoir rocks. Secondary migration terminates once the hydrocarbons encounter a trap, but may be re-initiated by tectonic events; known as ‘re-migration’ or ‘tertiary migration’. Secondary migration and the subsequent entrapment of petroleum is controlled by three parameters, the buoyant rise of petroleum in water-saturated porous rocks, capillary pressure, and hydrodynamic flow. The main driving force for secondary migration is considered to be density; in which hydrocarbons move in the direction of decreasing energy. Because oil and gas have lower densities than the surrounding, subsurface, aqueous pore fluid, the process of secondary migration is essentially driven by buoyancy, due to differences in density. The density differences are:

Oil s.g. = 0.5 to 1.0 g cm-3

gas s.g. = less than 0.01g cm-3

pore fluid s.g. = 1.0 to 1.2 g cm-3

Countering the buoyant rise of petroleum is capillary pressure. Within a multi-phase system consisting of immiscible phases (e.g. water and oil) an interfacial tension will exist across the contact interface. Capillary pressure is the pressure difference across the multi-phase interface. The greater the difference in interfacial tension between two phases, the greater the capillary pressure. When a small drop of oil is added to water, the oil globule assumes a shape of least surface area (Figure 37), which is a sphere due to interfacial tension (γ). The force required to distort that sphere, and subsequently drive the oil droplet through a small pore throat, is often referred to as the driving force or more correctly the injection pressure (Berg, 1975).

As a general rule, capillary pressure increases with increasing interfacial tension and/or decreasing pore throat diameter. The termination or continuation of movement is determined by an interplay between the driving force (e.g. density) and the resisitive force (i.e., capillary pressure). As shown in Figure 38, to drive an oil globule between the two grains, considerable energy must be exerted on the globule to overcome surface tension effects, increase the curvature of contact and reduce the effective radius of the oil. When the upper and lower radii (r) within the distorted globule are equal to one another, the capillary force is overcome and the globule can rise due to buoyancy.

Subsurface water flow may assist, modify, or even counter the movement of hydrocarbons. The existence of high capillary pressure within narrow rock pore throats is the main cause for hydrocarbon entrapment. Video 4 shows oil and water moving through porous media.

Figure 37. Surface tension on a droplet, the arrows show the pull of the attractive forces.

Figure 38. The movement of an oil globule (black) through a pore throat in water-wet rock (blue).The buoyant movement of the oil globule is opposed by capillary pressure until both the curvature contact and the internal radius (r) decrease and are equal at the lower and upper ends of the globule (right) (after Berg, 1975 and others). P = internal pressure within the globule γ = interfacial tension r = globule radius rp = globule radius outside the pore rt = globule radius inside the pore

Video 4. Oil and globules of water moving through a water-wet pore network. Note that each grain is coated with water (i.e., water wet) also note that water globules, e.g., ‘X’ are ‘distorted’ as they pass through the pore throats as shown in Figure 38 (Dong and Liu, 2007, used with permission)


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Post emplacement processes Introduction “The history of petroleum does not end when petroleum products are pooled into reservoirs” (Connan, 1984; p.299). Changes, sometimes subtle, effect petroleum after it leaves the source rock. Beyond the changes in composition that can occur during migration (e.g. fractionalization) several post-accumulation processes have the potential to modify petroleum within the reservoir or even during migration. For the most part, the alteration is generally considered destructive or a degrading process. For example, increases in temperature within the reservoir (i.e. in-reservoir maturation) will lead to a decrease in the relative proportion of higher molecular weight compounds (i.e. C15+) and a relative increase in the low molecular fraction. A decrease in pressure within the reservoir could lead to the deasphatling of petroleum through the precipitation of higher molecular weight compounds within the reservoir. Perhaps the two most prevalent alteration processes to effect reservoired petroleum include water-washing and microbial biodegradation. Degradation by the process of water-washing and the microbially-derived process of biodegradation is a widespread phenomenon, for example the seven largest super-giant accumulations of tar sands (degraded crude) contain as much oil as the 264 largest conventional oil fields (e.g. Athabasca tar sands, Western Canada, = 700 to 1000 × 109 bbl), due to the degradation of a medium gravity crude oil into a tar sand with an associate API gravity <10° (Larter et al. 2006; Koksalan et. al., 2006). Several stages of degradation are typically referred to, such as incipient, minor, moderate, and extensive to severe (e.g. Blanc and Connan, 1994) or given a numeric value using the scheme of Peters and Moldowan (1993).

Thermal cracking The thermal cracking of pooled petroleum can occur when the temperature within the trap increases. The characteristic changes of thermal cracking of pooled oil are considered (Blanc and Connan, 1994) to include an increase in the gas-to-oil-ratio (GOR), an increase in light hydrocarbon content and the production of a solid residue that is often, incorrectly, referred to as pyrobitumen. An excellent micrograph of pyrobitumen, from Western Canada, displaying an optical texture is given in Figure 39. Pyrobitumen contains very little hydrogen and is insoluble in a chlorinated solvent. The temperature at which thermal cracking is considered to occur varies from region to region, depending upon the pressure and temperature regime of the area. In general, an increase in pressure increases the thermal cracking threshold. For example, in Western Canada the threshold temperatures are considered to be between 93° to 104° C, in contrast to 150° C within the Niger delta and up to 175° to 204° C in parts of California (Blanc and Connan, 1994).

Water washing This process involves the removal of water-soluble compounds by flowing water within the trap. Low weight aromatic compounds (especially benzene and toluene) are the most soluble compounds, whereas the C15+ normal alkanes are typically unaffected. Consequently accumulations of pooled oil effected by water washing may exhibit a slight decrease in API° gravity and a loss in those compounds (Connan, 1984; Palmer, 1984).

Deasphalting The precipitation of solid residue containing asphaltene compounds can occur either because a decrease in pressure occurs within the reservoir or due to the introduction of gas into the pooled oil. The introduction of gas into the oil reservoir decreases the average molecular weight of the oil, promoting the precipitation of a solid residue (Blanc and Connan, 1994).

Figure 39. An example of pyrobitumen from Western Canada displaying an optical texture as seen in reflected white light using crossed polarized light (image courtesy of L. Stasiuk).


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Biodegradation The transformation and degradation of petroleum within a reservoir by living organisms (primarily bacteria) is considered to occur at relatively shallow depth in the presence of flowing water (Connan, 1984); although the bacterial degradation of oil can occur under both oxic and anoxic conditions (e.g. Zengler et al., 1999). High rates of degradation are seen within shallow reservoirs that are flooded by meteoric water (high sulfate and low salinity). For example, within Saskatchewan (Canada) reservoirs of Mississippian age the degree of biodegradation increases as the influx of low saline and sulfur rich water increases. Bacteria cannot live by oil alone! A sufficient supply of nutrients, such as nitrate and phosphate, are required in addition to a diet of hydrocarbons! Furthermore, the bacterial degradation of petroleum takes place at the oil-water interface, not within oil and at a rate that is dependent upon the oxic-anoxic conditions of the flowing water. Aerobic bacteria are the most effective, whereas anaerobic, sulfur-reducing bacteria are less effective (Connan, 1984; Aeckersberg et al., 1991). The time thought necessary to degrade petroleum within the reservoir petroleum was thought to be fairly long (e.g., ZoBell, 1973). However, recent work has suggested that under optimal conditions, the anaerobic biodegradation of reservoired oil can occur at rates of 10-6 to 10-7 year at 60 °C, and 10-2 to 10-1 year at the earth’s surface (Larter et al., 2000 and 2003). This would suggest that some transformation could occur within the life-span of many oil fields if care is not exercised during production.

Changes due to biodegradation Non-biodegraded oils are generally paraffinic, paraffinic-napthenic, or moderately aromatic in nature (see Introduction). In contrast, biodegradation leads to recognizable changes in oil type and the effect on gross properties is summarized in Table 6. The preferential removal of gases or compounds within the gasoline range generates a residuum of increased viscosity and °API gravity. A similar effect can also occur by water-washing, evaporation and/or atmospheric photo-oxidation. With progressive biodegradation, compositional changes include the removal of C15+ alkane and aromatic compounds and a relative increase in NSO-bearing compounds. Figure 40 shows a progression of effects upon reservoir oil due to biodegradation (Deroo et al., 1974). The relatively non-biodegraded oil from Bellshill Lake property contains the expected range of nalkanes, in contrasted to oils from Edgerton, Flat lake and Pelican Lake properties respectively, that show a marked increase in biodegradation marked by a progressive loss in nalkane content and a large pronounced 'baseline-hump'. Such changes are associated with a decrease in °API gravity, from an API of 28° for the Bellshill Lake oil down to 14° to 16° API for the Pelican Lake crude oil.

Figure 40. Gas chromatograms (alkanes) of progressively biodegraded oil from pools within Western Canada showing varying degrees of biodegradation. The small bar- charts show the relative distribution of nalkanes, isoalkanes and cycloalkanes (Deroo et al. 1974; reprinted by authority of the Canadian Society of Petroleum Geologists).

Table 6. A summary of changes in composition due to biodegradation (after Connan, 1984).

1. Dry & wet gas (C1 to C6) [DECREASE] 2. Gas/oil ratio [DECREASE] 3. Gasoline range (C6 to C15) [DECREASE] 4. APIo gravity [INCREASE] 5. Viscosity [INCREASE] 6. Compositional changes in C15+ compounds

alkanes [DECREASE] aromatics [DECREASE] NSO-bearing compounds [INCREASE]

7. Sulphur / sulfur content [INCREASE] 8. Nitrogen content [INCREASE] 9. Metal content (e.g. V and Ni) [INCREASE] 10. Pour Point [DECREASE] 11. Possible changes in oil type

Original oil type Altered oil type Paraffinic → Naphthenic Paraffinic-naphthenic → Aromatic-Naphthenic Paraffinic condensate → Naphthenic condensate Condensate → Light oil Aromatic-intermediate → Aromatic-asphaltic


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chapter 04 subsurface reservoir trap basin

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