1 SOURCE ROCK EVALUATION By DR.MUHAMMAD MUJTABA ISLAMABAD. May 30, 2010 2 TABLE OF C O TE TS Page A Geochemical Approach to Basin Evaluation 1 Sample Collection 1 Source Rock Potential 2 Organic Matter 2 Depositional Setting 4 Geologic age 5 Paleo Latitudes 6 Structural Forms 7 Biologic Evaluation 8 Kerogen 12 Maturity ........................................................................................... 12 Source Rock 14 Diagenesis 14 Catagenesis 14 Total Organic Carbon (TOC) 14 Pyrolysis 15 S1, S2, S3 Peaks 16 Tmax (°C) 17 Hydrogen Index (HI) 17 Source Rock Maturity Summary 18 Transformation Ratio 19 Organic Matter 19 Thermal Maturity and Hydrocarbon Generation 20 Stages of thermal maturity 21 Geochemical Modeling 22 Preservation of organic matter 23 Thermal Maturity Modeling 23 Hydrocarbon Migration 25 Resource Assessment 26 Hydrocarbon Geochemistry 28 Oil geochemistry 28 Gas geochemistry 29 3 Correlation Studies 30 Petroleum System 30 Sedimentary Basin Investigations 31 Petroleum System 31 Play and Prospect Investigation 31 Petroleum System 32 Level of Certainty 33 Pod of active source rock 33 Petroleum definition 34 Investigation Technique 34 Overburden Rock 36 Formation of Sedimentary Basin 38 Types of sedimentary basin 38 Structural and Thermal Evaluation of Sedimentary Basin 40 Source of Heat 40 Estimating Temperature and Heat Flow 41 Temperature 41 Thermal Conductivity 41 Surface temperature 42 Sedimentation 42 Groundwater Flow 42 Processes 43 Diagenesis, Catagenesis & metagenesis 43 Oil expulsion through Pyrolysis 44 Secondary migration & accumulation 45 Establishing migration direction 45 Seal 45 Subsidence history 46 Decompaction 47 Tectonic Subsidence 48 Paleobathymetric correction 48 Eustatic Correction 48 Sediment Load 48 Thermal History 48 4 Arrhenius equation 49 Pale temperature 49 Effect of thermal Conductivity 50 Effect of internal heat generation 50 Effect of Water flow 50 Indicators of formation temperature 50 Vitrinite reflectance 50 Other burial indices 51 Geothermal and Pale-geothermal signatures of basin types 51 References 78 5 List of Figures Figure 1: Kerogene transformation coefficients (after Waples, 1980) 58 Figure 2: Thermal conductivity of common rocks. 58 Figure 03: Components of hydrocarbon supply and composition assessment. 59 Figure 4: Inert Kerogene. 59 Figure 5: Pyrolysis-gas choromatogram of lacustrine shale (Alkesinac shale, Yugoslavia) 60 Figure 6: Pyrolysis-gas choromatogram of marine shale (Kimmeridge Shale, orth Sea) 60 Figure 07: Pyrolysis-gas choromatogram of shale dominated by vitrinitic material (Tertiary, Gulf of Mexico) 61 Figure 08: Pyrolysis-gas choromatogram of degraded marine organic matter (Cretaceous, DSDP site 534). 62 Figure 09: Pyrolysis-gas choromatogram from a sample dominated by inert kerogen. 62 Figure 10: Classification of the three main types of kerogen in a HI vs OI diagram. 63 Figure 11: HI T max diagram. 64 Figure 12 effect of weathering on various geochemical indices. 64 Figure 13: Changes in vitrinite reflectance with increasing thermal maturity. 65 Figure 14: ormal vitrinite reflectance profile from China Sea. 65 Figure 15: effect of different kinetics on hydrocarbon generation (from Tissot et al. 1987). 66 Figure 16: Petroleum components. 66 Figure 17: Gross composition of normal producible crude (from Tissot and Welte 1984) 67 Figure 18: Oil Classification scheme based on bulk geochemical character (after Tissot and Welte, 1984). 67 6 Figure 19: hydrocarbons observed in modern algae (After Gelpi et al., 1970). 68 Figure 20: Effects of biodgradation on the saturated fraction of a suite of crude oil from the iger Delta. 69 Figure 21: Summary of effects of biodegradation on chemical and physical properties of crude oils (from Clayton, 1990) 69 Figure 22: Schematic representation of the development of sour (high sulfur) crude oils. 70 Figure 23: Precursors for the major biomarker classes (Waples. 1985) 70 Figure 23 B: names and various ways of depicting n-alkanes (from Waples, 1985). 71 Figure 24: relationship between precursor and n-parafin distribution (from Lijmback, 1975). 71 Figure 25: An example of the use of methane carbon isotopic composition to determine probable source. 72 Table 1.3. Oil and Gas Fields in the Fictitious Deer-Boar (.) Petroleum system, or the Accumulation related to One Pod of Active Source Rock. 72 Figure 26. 72 Figure 27: Burial history chart showing the critical moment (250 MA) and the time of oil generation (260-240 Ma)for the fictitious Deer-Boar(.) petroleum system. This information is used on the events chart (Figure 1.5). eogene ( ) includes the Quarternary here. All rock unit names used here fictitious. Location used for burial history chart is shown on figures 1.3 and 1.4. (Time scale from Palmer 1983.). 73 Figure 28: Plan map showing the geographic extent of the fictitious Deer-Boar (.) petroleum system at the critical moment (250 Ma). Thermally immature source rock is outside the oil window. The pod of active source rock lies within the oil and gas windows. (Present day source rock maps and hydrocarbon shows on figure 5.12 and 5.13, Peters and Cassa, Chapter 5, this volume). 73 Figure 29: geological cross section showing the stratigraphic extent of the fictitious Deer- Boar (.) petroleum system at the critical moment (250 Ma). Thermally immature source roack lies updip of the oil window. The pod of active source rock is downdip of the oil window. (The present day cross section is shown in figure 5.12 F, Peters and Cassa, Chapter 5, this volume.) 75 7 Figure 30: the events chart showing the relationship between the essential elements and processes as well as the preservation time and critical moment for the fictitious Deer-Boar (.) petroleum system. eogene ( ) includes the Quaternary here. (Time scale from Palmer, 1983.) 74 Figure 31: Geochamical log for well 1, showing immature and mature source rocks in the Upper and Lower Cretaceous (see tables 5.1-5.3). Mud gas data were unavailable for this well. 75 Figure 32: Representative tectonic subsidence histories for basins from different tectonic settings. The top graph shows the slops of a range of sedimentation rates after compaction and is provided for reference (After Angevine et al., 1990.) 76 Figure 33: Summary of the typical heat flows associated with sedimentary basins of various types. 77 8 THERMAL MATURITY MODELI G • Thermal maturity modeling provide the only reliable mechanism, to both, extrapolate the level of thermal maturity away from the subsurface control and estimate the timing of hydrocarbon generation and expulsion. • Previously, all of the approaches to maturation modeling were based on the concept that specific time-temperature histories will result in a predictable level of thermal maturity (Lopatin, 1971; and Waples, 1980). Much of this is based on empirical data which relate present-day temperature and stratigraphic age to the observed level of thermal maturity. • At present there are two approaches to thermal maturation modeling: 1. One method is based on empirical-derived relationships between time, temperature, vitrinite reflectance and and other apparent indices of hydrocarbon generation (Wapless, 1980). This approach is commonly referred to as the Lopatin method. 2. The second approach is more rigorous (Tissot et al., 1987; and Wood, 1988) and is based on the extrapolation of high temperature pyrolysis (Abbot et al., 1985; Lewan, 1985, Saxby et al., 1986; Quigley and Mackenzie, 1988 and Issler and Snowden, 1990) to determine the kinetics (i.e. the science of the relationship between the motions of bodies and the forces acting on them) of hydrocarbon generation (Campbell et al., 1978; Burnham and Braun, 1985; Braun and Burnham, 1987; Burnham et al., 1987; Ungerer and Pelet, 1987; and Zhang Youcheng et al., 1991) and the use of the Arrhenius reaction to predict the K = Ao Exp-Ea/RT rate of kerogene conversion. This second approach is referred to as kinetic method. • In both above noted approaches, modeling input requires burial history (including estimates the of erosion and periods of nondeposition), present and past subsurface temperature and surface temperature history. • In the case of the kinetic method, the investigator also needs to supply the kinetic parameters, associated with the source rock (Ao – the frequency factor and Ea – the activation energy). This is not required in the Lopatin method because the apparent rates of maturation have been predefined. • The most commonly utilized Lopatin approach assumes that there is a doubling of reaction rate for each 10Co increase in temperature (Fig. 1). • Although the calculations are different for the two models, they both rely upon the creation of a detailed burial/thermal history of the sedimentary package. This history is then used to reconstruct the development of the maturation history and profile. • A series of sensitivity analysis has shown that the timing of hydrocarbon generation is more sensitive to the input parameters than is the absolute level of calculated thermal maturity. • Geothermal input into models can vary significantly. The simplest case assumes the utilization of a single constant geothermal gradient through time. Such simplification may be considered generally valid in regions underlain by continental crust (excluding geothermal regions) in old occanic crust regions (when the sedimentary section, being modeled, was deposited late in the basins history); in regions where the crust has undergone only minor 9 amounts of extension; and if there are no major changes in the nature of the lithologic column. • A constant geothermal gradient is, however, not appropriate in young extensional basins; in basins which has undergone substantial amounts of extensions; and in nonequilibrated overthrust and foreland belt regions. • A constant geothermal gradient is also inappropriate if there are large contrast in the thermal conductivity, and if there is nonconductive heat transport (i.e., hydrothermal fluid flow). In such cases, both temporal (existing in time) and down-hole changes, in the thermal gradient, must be incorporated into the model input. • Present-day thermal information may be obtained from down-hole measurements or through the use of regional heat flow information, along with the information on the thermal conductivity of the sedimentary section (Fig. 2). • Although both modeling approaches are capable of reproducing the present-day vitrinite reflectance profile and maturation history, only the kinetic model is able to present information directly on the extent of kerogene conversion that has occurred. They may be presented as a depth profile of the relative proportions of oil, gas and residue as a function of depth or as a function of time. Such information can be presented in map view to show regional generation pattern. • The timing of petroleum generation, expulsion and degradation is important when placed in context with the timing of trap development. It is possible that if trap development followed oil generation, the trap would be barren. • Once the regional thermal maturity framework is established and the distribution of source rocks is known, these data can be integrated to outline the generative portions of the basin. These are the portions of the basin where source rocks either are presently generating or have in the past generated hydrocarbons. • It is only the volume of source rock, within the generative basin, that contributes to the overall basin’s resource base. GEOCHEMICAL MODELI G • Unfortunately, hydrocarbon source rocks are not generally sampled while drilling a well; and if sampled either in outcrop or in the subsurface, are commonly immature. • This is because of two factors: 1) most drilling targets are associated with high energy depositional environment, while source rock systems develop within low energy systems; 2) source rocks encountered either in the subsurface or in outcrop, have not usually experienced the most favourable burial history for the generation of hydrocarbons. • Wells are generally drilled on structural highs above the oil-window rather than within the generative deeps within a basin. • At the same time, outcrop localities tend to be often located along basin margins or flanks, once again away from the regions that experienced the most favourable burial history for oil and gas generation. 10 • This lack of sample control has resulted in the development of a series of geochemical models that qualitatively predicted the distribution of oil and gas prone source systems, and quantitatively predict the level of thermal maturation and degree of hydrocarbon generation. A GEOCHEMICAL APPROACH TO BASI EVALUATIO • The primary job function of a petroleum explorationist is to utilize all the available data to reduce the risks associated with petroleum exploration. Such an analysis requires a fully integrated approach using many aspects of geoscience. • In practice, however, in petroleum exploration there has been commonly an emphasis on predicting hydrocarbon trap capacity. This is largely accomplished through the use of seismic reflection data to define the volume of rocks under closure (prospect generation). • This estimate is further refined by assuming a net reservoir thickness and an average porosity. Petroleum engineers are commonly given this information along with largely arbitrary fill-up factors to assess exploration economics. • This is interesting to note that nowhere in this approach there has been any attempt to determine the amount and type of hydrocarbons that actually may be available for entrapment. • Organic geochemistry is the only effective means of directly addressing the problems associated with the amount and nature of the reservoired fluids. • The determination of the characteristics of the reservoired fluid is accomplished by examining the richness, organic geochemical character of the various source sequences and the level of thermal maturity of the various source and reservoir sequences within a basin. • These geochemical attributes are commonly measured directly. However, because of the limited number of wells as well as the geologic settings of both surface and outcrop samples, analytical data needs to be supplemented by geologic and numeric modeling results (Fig. 3). ORGA IC MATTER • Oil-prone organic matter appears as distinct algal bodies, plant cuticle, spores and pollen grains and fluorescent amorphous material. The fluorescent amorphous material is believed to have been derived by the bacterial reworking of algal material. • Gas-prone organic matter appears as woody structural material (vitrinite) or as nonfluorescent amorphous material. • Nonfluorescent amorphous material may be derived either as a result of an advanced level of thermal maturity (Ro greater than 0.9%) of originally fluorescent amorphous material, or through the bacterial or fungal degradation of structured organic matter. 11 • Inert organic matter usually appears as black, structured organic matter in transmitted light and highly reflective under reflected light. Much of this material has either been recycled or severely oxidized prior to its final deposition (Fig. 4). • Although the above mentioned methods provide some information on oil or gas proneness, they do not provide detailed information on the actual character of the generated hyrocarbons. More detailed information, however, can be obtained through the use of pyrolysic-gas chromatography. • In simple terms, in pyrolysis-gas chromatography, a sample is heated in an inert atmosphere. The generated products are collected using a cold trap. These hydrocarbons are then introduced in a gas chromatographic column for analysis. It is important to note that these products are similar but not identical to naturally occurring products. The primary difference is that the pyrolysis products contain substantial amounts of unsaturated hydrocarbon compounds. • Pyrolysis-gas chromatographic results can be used either qualitatively or quantitatively. Qualitatively the chromatographic fingerprints are compared to a set of known signatures to establish depositional environments, to assess the oil versus gas proneness and to determine the relative waxiness of the generated products. • A series of such standard or typical chromatographic ‘fingerprints’ is presented below: • Locustrine samples produce chromatograms dominated by alkene-alkene doublets (Fig. 5). The samples contain significant quantities of waxy C22+) compounds. The chromatographic fingerprints are grossly similar for both carbonates and shales. There are, however, some differences, which are largely manifested in the normalized alkane-alkene distribution and can be related to differences in the original biomass. • Samples containing well-preserved marine organic matter display chromatographic patterns which include significant naphthenic envelopes, a well-defined series of alkane-alkane doublets, which exhibit a harmonic decrease with increasing carbon number (Fig. 6). • Samples, dominated by vitrinite, produce chromatographic patterns which include abundant aromatic compounds as well as significant contributions by various phenolic compounds (Fig. 7). • Samples, containing poorly preserved marine organic matter, produce chromatograms with poorly defined peaks (Fig. 8). • It is important to note that neither Rock-Eval pyrolysis nor elemental analysis could effectively differenciate between type III organic matter derived from terrestrial or marine sources. • Samples dominated by inert organic produce chromatograms that are little more than a baseline trace (Fig. 9). • Quantitatively, pyrolysis-gas chromatography results are interpreted by comparing the relative abundance of C1-C5, C6-C14 and C15+ fractions. The relative abundance of these compounds establishes the oil-versus gas-proneness of the organic matter as well as its tendency to generate waxy products. • Petroleum classification or gross composition can also be inferred using the relative abundance of aromatic, n-alkyle and resolved unknown compounds. 12 Organic Matter • There is now a wealth of geochemical evidence that petroleum is sourced from biologically derived organic matter buried in sedimentary rocks. • Organic-rich rocks, capable of expelling petroleum compounds, are known as source rocks. • Source beds form when a very small proportion of the organic carbon, circulating in the Earth’s carbon cycle, is buried in sedimentary environments where oxidation is inhibited. • The carbon cycle is initiated by photosynthesizing land plants and marine algae, which convert carbon dioxide present in the atmosphere and seawater into carbon and oxygen using energy from sunlight. Carbon dioxide is recycled back in many ways, such as: i) animal and plant respiration (bringing carbon dioxide back to the atmosphere), ii) bacterial decay and natural oxidation of dead organic matter, and iii) combustion of fossil fuels (both natural and by man). • From petroleum geology point of view, the small proportion of carbon, which escapes from the cycle as a result of deposition in such sedimentary environments where oxidation to organic matter is limited, is important. Such environments are generally depleted in oxygen, such as, some restricted marine basins, deep lakes and swamp environments, which are toxic for bacteria. • Petroleum is, therefore, sourced from organic carbon that has dropped out of the carbon cycles at least for some time. It, however, rejoins the cycle when extracted by man and combusted. • Much of the world’s oil has been sourced from marine source rocks. Source beds may develop in enclosed basins with restricted water circulation (reducing oxygen supply) or on open shelves and slopes as a result of upwelling or impingement of the oceanic midwater oxygen-minimum layer. • In the world oceans, simple photosynthesizing algae (phytoplankton) are the main primary organic carbon producers. Their productivity is controlled primarily by sunlight and natrient supply. • The zones of highest productivity are in the surface waters (euphotic zone) of continental shelves (rather than open ocean) in equatorial and mid latitudes, and in areas of oceanic upwelling or large river input. • The productivity of land plants is controlled primarily by climate, particularly rainfall. Coals have formed in the geological past predominantly in the equatorial zone and in cool wet temperate zone centered at about 55o (N and S). • All living organic matter is made up of varying proportions of four main groups of chemical compounds. These are carbohydrates, proteins, lipids and lignin. • Only lipids and lignin are normally resistant enough to be successfully incorporated into sediment and buried. • Lipids are present in both marine organisms and certain parts of land plants, and are chemically and volumetrically capable of sourcing the bulk of the world’s oil. 13 • Lignin is found only in land plants and cannot source significant amounts of oil, but is an important source of gas. • Geochemical studies of coal macerals have shown a very significant oil potential among the exinite group, comprising material derived from algae, pollen and spores, resins and epidermal tissue. • The organic compounds, provided to the sea bottom sediments by primitive aquatic organisms, have probably not changed dramatically over geological time. • In contrast, however, important evolutionary changes have taken place in land plant floras. As a result, a distinction can be made between the generally gas-prone Paleozoic coals, and the coals of the Jurassic, Cretaceous and Tertiary, which may have an important oil-prone component. • Anoxic conditions (oxygen-depleted) are required for the preservation of organic matter in depositional environments, because they limit the activities of aerobic bacteria and scavenging and bioturbating organisms which otherwise result in the destruction of organic matter. • Anoxic conditions develop where oxygen demand exceeds oxygen supply. Oxygen is consumed primarily by the degradation of dead organic matter; hence, oxygen demand is high in areas of high organic productivity. • In aquatic environments, oxygen supply is controlled mainly by the circulation of oxygenated water, and is diminished where stagnant bottom waters exist. • Other factors are: the transit time of organic matter in the water column from euphotic zone to sea floor, sediment grain size, and sedimentation rate which effect source bed deposition. Depositional Settings • The three main depositional settings of source beds are lakes, deltas and marine basins. • Lakes are the most important setting for source bed deposition in continental sequences. Favourable conditions may exist in deep lakes, where bottom waters are not disturbed by surface wind stress, and at low latitudes, where there is little seasonal overturn of the water column and temperature-density stratification may develop. In arid climates, a salinity stratification may develop as a result of high surface evaporation losses. • Source bed thickness and quality is improved in geologically long-lasting lakes with mineral clastic input. • Organic matter on lake floors may be autochthonous, derived from fresh water algae and bacteria, which tends to be oil-prone and waxy, or allochthonous, derived from land plants swept in from the lake drainage area, which may be either gas-prone or oil-prone and waxy. • The Eocene Green River Formation of the western USA, and the Paleogene Pematang rift sequences of central Sumatra, Indonesia are examples of rich, lacustrine source rock sequences. • Deltas may be important settings for source bed deposition. Organic matter may be derived from freshwater algae and bacteria in swamps and lakes on the delta-top, marine 14 phytoplankton and bacteria in the delta-front and marine pro-delta shales and probably most important, from terrigenous land plants growing on the delta plain. • On post-Jurassic deltas in tropical latitudes, the land plant material may include a high proportion of oil-prone, waxy epidermal tissue. Mangrove material may be an important constituent. • Examples of deltaic source rocks include the Upper Cretaceous to Eocene Latrobe Group coals of the Gippsland basin, Australia. • Much of the world’s oil has been sourced from marine source rocks. Source bed may develop in enclosed basins with restricted water circulation (reducing oxygen supply), or on open shelves and slopes as a result of upwelling or impingement of the oceanic midwater oxygen-minimum layer. • Examples of modern enclosed marine basins include the Black Sea and Lake Maracaibo. Source bed deposition is favoured by a positive water balance, where the main water movement is a strong outflow of relatively fresh surface water, leaving denser bottom- waters undisturbed. • The Upper Jurassic Kimmeridge Clay Formation of the North Sea, and Jurassic Kingak and Aptian-Albian HRZ Formations of the North Slope, Alaska, are examples of source rocks deposited in restricted basins on marine shelves. • The time of oil and gas generation cannot always be equated with the time of trapping. Under certain conditions, generated oil can be retained in source rocks for a long time. This situation may occur when source rock is separated from reservoir rock by an impermeal seal. This oil can be released later due to fracturing of the seal caused by tectonic and other processes. • More than 90% of original recoverable oil and gas reserves in the world has been generated from source rocks of six stratigraphic intervals, which represents only one-third of Phanerozoic time. The six stratigraphic intervals are 1) Silurian (generated 9% of the world’s reserves), 2) Upper Devonian-Tournaisian (8% of reserves), 3) Pennsylvanian- Lower Permian (8% of reserves), 4) Upper Jurassic (25% of reserves), 5) Middle Cretaceous (29% of reserves), and 6) Oligocene-Miocene (12.5% of reserves). • This uneven distribution of source rocks in time displays no obvious cyclicity and the factors that controlled the formation of source rocks vary from interval to interval. • There are several primary factors which controlled the areal distribution of source rocks, their geochemical type and their effectiveness (i.e., the amounts of discovered original conventionally recoverable reserves of oil and gas generated by these rocks). These factors are geologic age, paleolatitude of the depositional areas, structural forms (basin configurations) in which the deposition of source rocks occurred, and the evolution of biota. Geologic Age • Jurassic was a time of exceptionally warm climates that presumably permitted favourable oil-prone rock development even in high latitudes in the North sea, West Siberia and possibly even Antarctica. 15 • The most important change in the character of source rocks, during the Phanerozoic, was the appearance and expansion of source rocks containing type III Kerogene and Coal. The effectiveness of these source rocks also grew, reaching its maximum in the Oligocene- Miocene. • A significant increase in areas of type III Kerogene and coal is accompanied by a relative decrease in areas covered by Kerogene type I and II rocks. Rocks with type I kerogene are rare and are insignificant, as according to latest analysis, they have provided approximately 2.7% of the original reserves of world petroleum. • With the expansion of source rocks, containing type III kerogene, there seams to be gradual elimination of marine environments favourable for deposition of facies enriched in sapropelic (type II kerogen) organic matter, primarily the black shale facies. Paleo latitudes • A warm, moist climate, characteristic of low to middle paleolatitudes, supports abundant life, such as very highly bioproductive tropical rain forests on the land and reef communities on the continental shelf. This climate is believed to be favourable for source rock deposition. • Study shows that areally two-thirds of the source rocks of the above noted six principal stratigraphic intervals were deposited between the paleoequator and 45-degree paleolatitudes. • Low latitudes were more favourable for deposition of source rocks with kerogene types I and II. In contrast, more source rocks containing kerogene type III and coal were deposited in high latitudes (except for the Oligocene-Miocene interval). • A very high effectiveness of source rocks with kerogene types I and II, deposited in low latitudes, is connected with the widespread presence of carbonate reservoir rocks and evaporite seals that helped trap and retain petroleum. • Beginning in the Late Jurassic, source rocks with kerogene types I and II became noticeably more common in high latitudes. Deposition and preservation of organic matter in high latitudes were probably helped by the globally warm Mesozoic climate. Black shale facies of this age extended over large areas of Arctic seas. • A very different areal distribution is, however, the characteristic for source rocks that contain dominant type III kerogene and coal. These source rocks appeared in minor amounts in the Late Devonian-Tournoisian at low latitudes. In the Pennsylvanian-Early Permian and Mesozoic, the largest depositional areas of potential source rocks with type III kerogene and coal were located in high paleolatitudes. During Tertiary, however, source rocks with type III kerogene and coal again were deposited mostly at low paleolatitudes and primarily in large deltas. Note: It may be noted that the causes of this distribution, of kerogene types I, II and III, are not exclusively biologic. - Very little organic matter is usually found in sediments of the ecologically most favourable zones, such as, reefs. In contrast, deposition of black shales was aided by the extremely 16 abundance of a limited number of forms, commonly blue-green algae (cyanobacteria) and green algae. - Other factors are also important, such as, higher reproduction rates (and thus higher bioproductivity), especially in winter, and the absense of a seasonal overturn of water in hydrologically stagnant basins, which favour deposition and preservation of organic matter in tropical and subtropical seas. - On land, great bioproductivity is characteristic of tropical rain forests; however, peat bogs and other accumulations of organic material are uncommon there because of the high rate of organic matter decomposition. - Only for source rocks with kerogene types I and II, deposited in low paleolatitudes, the effectiveness greatly exceed the areal extent, as compared to the effectiveness of source rocks with type III kerogene. - Similarly, the quality of kerogene types I and II in source rocks of high paleolatitutdinal zones (e.g., North Sea, West Siberia) is very good. - The higher effectiveness of source rocks with kerogene types I and II in low paleolatitudes is connected to the high reservoir capacity of widespread carbonate reservoir rocks, besides the siliciclastic reservoirs. Whereas, in polar and subpolar regions, only siliciclastic rocks are potential reservoirs, and many of them are characterized by ‘dirty’ lithology. - An additional important factor is the widespread presence of evaporite seals in low paleolatitudes. - Black shale facies, with type II kerogene, carbonate (and specially reefal) reservoir rocks, and overlying evaporites commonly were genetically and spatially related. This close relationship resulted in a high endowment of oil and gas. - A genetic and spacial connection does not exist among siliciclastic reservoir rocks, seals and source rocks with type III kerogene and coal. This is why the effectiveness of these source rocks, whether deposited in low or high paleolatitudes, does not vary significantly. Structural Forms • Structural forms, reflecting tectonic stages in basin development, affect source rock deposition. • The structural development resulted in the formation of characteristic types of relief, appearance of sources of clastic material and rates of subsidence and sedimentation. • Development of most basins passed through different tectonic stages. These tectonic stages are expressed as successive structural forms, which existed during the corresponding time interval. • The number of basic structural forms is limited, although the size of individual structures can vary significantly. The basic structural forms are: 1) platforms, 2) circular sags, 3) linear sags, 4) rifts, 5) foredeeps, 6) half sags, and 7) deltas. • Each structural form is characterized by the morphology of a sedimentary body deposited in the structure. • Platforms are areally large sheets of relatively thin sedimentary rocks on cratons and less commonly, on accreted zones (epiplatforms) that dip gently toward the ocean. 17 • Circular sags commonly are larger than linear sags and overlie branching rift systems or fill depressions over basaltic windows in continental crust. • Linear sags are strongly elongated depressions with gently sloping limbs and most commonly overlie single rifts. • Half sags are asymmetric sedimentary bodies composed of the seaward prograding wedges of clastic rocks and carbonate bank sediments. • Rifts are linear horst and graben depressions bounded by deep-seated faults. • Foredeeps are asymmetric troughs developed between an orogenic belt and a foreland, and are largely filled with molasse deposits derived from the orogen. • In this study, deltas are very thick sedimentary bodies located on the continental margins (commonly along a triple junction). Some deltas are similar to half sags, but because of great sedimentary loading, deltas commonly develop partly closed central sag. • Three, out of the above noted seven structural forms, are responsible for the bulk of oil and gas reserves. Source rocks, deposited in these three structural forms, i.e., platform, circular sags and linear sags, provided more than three-quarters of original reserves generated from the six principal intervals. • Effectiveness of source rocks with type III kerogene and coal varies little in different structural forms, whereas analogous variations for source rocks with kerogene types I and II is very significant. • Petroleum reserves, generated by type I kerogene, are not large; they constitute approximately 2.7% of original petroleum reserves. • It may be thus concluded that structural forms controlled primarily the deposition of source rock with type II kerogene, which is dominantly black shale facies. • Deposition of black shale facies occurred chiefly under anoxic and dyoxic conditions. Thus, over geologic time, these conditions occurred preferentially on platforms and in circular and linear sags; less commonly these conditions formed in rifts and foredeeps, very rarely in half sags and almost never in deltas. • Deposition of effective source rocks on platforms occurred primarily in the Silurian and Late Devonian-Tournaisian. • In the Late Jurassic and Middle Cretaceous, the principal effective source rock deposition was controlled by linear and circular sags. • Half sags and deltas controlled source rocks deposition only during the Oligocene-Miocene. • The bulk of the effective source rocks in rifts and foredeeps was deposited during the Pennsylvanian-Early Permian and the Oligocene-Miocene, which correspond to the climaxes of the orogenics. Note: It may be mentioned over here that tectonics does not completely account for the changed role of various structural forms in source rock deposition through time. It is suggested that one of the important causes of this change was the evolution of life. 18 Biologic Evolution • The significance of biologic evolution for oil and gas genesis is poorly understood. Only the development of higher land plants during the middle Paleozoic, resulting in the appearance of terrestrial organic matter as a new source for oil and gas, is commonly referred to. • Each ecologic community, since at least the late Proterozoic, consists of producers (photosynthetic plants), consumers (animals) and decomposers (aerobic and anaerobic bacteria and saprophytes). • In the oxic marine environment, the bulk of organic matter is consumed by metazoans, and the role of bacteria decomposition is limited. • In the anoxic environment, consumers are absent and all the organic matter is subjected to bacterial decomposition. However, the anaerobic bacterial decomposition does not result in complete oxidation of organic matter. Its more stable components, such as lipids, tend to accumulate in sediments. • In the terrestrial conditions, much of bioproduction (e.g. wood) is not digestable for most animals and is decomposed by aerobic bacteria and saprophytic plants. • The amount of organic matter buried in marine sediments depends little on the rate of bioproduction. This amount is controlled primarily by the balance between bioproduction and destruction (consumption and decomposition) of organic matter. • In many highly bioproductive areas, such as upwelling zones, the amount of organic matter is sediments is insignificant. In contrast, many black shale facies were deposited under conditions of low bioproductivity. • The inorganic oxidation of organic matter, as compared to the biologic destruction, is highly inefficient. Therefore, the amount and quality of deposited organic matter depend on the activity of consumers and decomposers. At present, this activity (excluding anaerobic bacteria) is regulated by the availability of oxygen at and near the sediment surface, and the deposition of marine black shale facies with type II kerogene occurs primarily on oxygen depleted sea bottom. • There are, however, many indications that in the late Proterozoic-early Paleozoic, deposition of organic-rich rocks commonly occurred not only under anoxic but also dyoxic and even oxic conditions. • A very shallow-water carbonate and even reefal oxic environment was suitable for deposition of source rocks in the late Proterozoic. In many regions, stromatolitic dolomites are rather rich in organic matter. These dolomites are source rocks for oil and gas fields and shows and for bitumen deposits in China, northern Siberian Craton and eastern Russian Craton. • Organic-rich stromatolitic carbonate rocks have not, however, been formed since the Cambrian. • The deposition of abundant organic material under oxic and dyoxic conditions during the late Proterozoic to middle Paleozoic may indicate that consumers and decomposers did not fully use oxygen and organic matter as the available energy source. 19 • Worms and other soft-bodied burrowing animals are the major consumers of organic matter in the upper layer of sediments. • During the late Paleozoic and Mesozoic, black shale facies were restricted chiefly to relatively deep-water (commonly below a few hundred meters), semi-enclosed basins separated from the open sea by structural barriers or reefs. Linear and circular sags and to a lesser extent, rifts were the most favoured for formation of these basins. • Beginning from the latest Cretaceous, the major black shale deposits were formed in deep, almost completely isolated, euxinic basins. The principle basins of this type were formed in depressions of the Alpine fold belt and in some rifts. • In the semi-enclosed silled basins, the black shale facies was essentially replaced by organic-lean Globigerina ooze. • The flourishing of planktonic foraminifers, that began in the Late Cretaceous, could have significantly decreased the bioproduction because the foraminifers fed mainly on phytoplankton. • The evolution of diatoms that flourished in the Tertiary was also significant for deposition of source rocks. Diatoms have an extremely high lipid content that reaches 40% of their weight. • The evolution and expansion of terrestrial plants, after the Silurian, brought about a new source of organic matter. • Until the Permian, plants primarily occupied seashores, resulting in the dominance of paralic coals. Limnic coals first appeared in the Late Carboniferous, but became widespread in the Mesozoic and reached their maximum abundance in the Tertiary. • The Mesozoic forestation of vast land areas resulted in the appearance of forest lakes surrounded by swamps. These lakes were ephemeral and quickly became bogs with peat deposition. Resulting coal-bearing deposits contain lacustrine beds rich in alginite (gyttja) and are an oil source in generally gas-prone sequences. • The evolutionary changes in plants and the inland expansion of forests account for the increasing proportion of oil in petroleum, generated from source rocks with dominant type III kerogene and coal from the late Paleozoic. • However, the variety of environments favorable for formation of source rocks with type II kerogene decreased significantly. This decrease brought about the gradual diminishing of the role of marine black shale facies as the most important generator of petroleum. The black shale facies were essentially replaced by source rocks with type III kerogene and coal. • Eustatic transgressions, Global Climate and Ocean Hydrodynamics are believed to affect source rock deposition. • Climatic control on deposition of continental source rocks with type I and type III kerogene is well known. • Worldwide transgressions caused by deglaciation and changes in the ocean topography cover large continental areas. Transgressions are believed to be highly favourable for black shale deposition in continental basins. The depositional model includes global warming, weak ventilation of oceans by oxygen-rich polar water, expansion of the oxygen-deficient layer, and its impingement on the continental slopes and shelves. 20 • Many widespread black shales, on shallow shelves, were deposited during geologically short periods of time. In many regions, only one black shale interval is present in the geologic column. • The Pacific and south Gondwana realms are relatively poor in oil and gas. Much of the petroleum in both realms is high-wax oils resulting from either type I and type III kerogene. • The deposition of thick Alpine molasses played the major role in burial and maturation of source rocks. Thus, the majority of oil and gas is very young. About two-thirds of original petroleum reserves was generated and trapped during the last 80-90 m.y., a rather short interval of the Phanerozoic geologic history. • It is significant that a large portion of the recoverable petroleum resources are found in only a few selected localities. • It is believed that, worldwide recoverable conventional oil and gas, exist in ultimate quantities approximating 2300 billion barrels of oil and 12,000 trillion cubic feet of gas. • The source rock deposition was aided by the successive opening and collisional closing of proto-Tethys, paleo-Tethys and new-Tethys that developed rift/sag structural forms favourable for the formation of silled basins. The Tethyan basins were developed over less than one-fifth of the world’s land and continental shelves, yet they contain over two-thirds of the original petroleum reserves. • Unconventional resources, such as extra heavy oils, bitumen, tar sands, gas in tight sands and coal bed methane, are present in large-quantities. They are, however, expensive to recover at adequate rates of production and sometimes expensive to alter the quality necessary for modern day use. We don’t know at present that how, if, or when they will become major components of world energy consumption. • Similarly, natural gas hydrates, which occur widespread and in potentially recoverable large quantities, will ever prove to be a commercial source of energy. • Proved Reserves of oil are generally taken to be those quantities which geological and engineering information indicate, with reasonable certainty, can be recovered in the future from known reservoirs under existing economic and operating conditions. • No new discovery areas have evolved to alter the broad distribution of world oil and gas resources. The Middle East, North America and the former Soviet Union still account for about 75 percent of world petroleum resources. • It is believed that paleoclimate conditions, within the 30o latitude boundaries, surrounding the equator, are the most favourable for source rocks, carbonate reservoir rocks and Salt seals. Accordingly, most oil and gas have been found and will continue to be found in the geologically equatorial Tethyan Realm. • The Boreal Realm to the north, because of its Paleozoic equatorial plate tectonic position, likewise is rich in oil and gas, but the South Gondwana Realm continents have poor properties of oil occurrence owing to the long history of high-latitude geographic association with Antarctica. • The Pacific rim doubtless experienced climatic effects but, more important, overriding tectonic subduction events destroyed most of the stratigraphic column and introduced volcanic debris into potential reservoir porosity, thus limiting the oil and gas occurrence. 21 • In variance to the hypothesis, however, gas prone source rock are viable in intermediate to high latitudes and furthermore, Jurassic was a time of exceptionally warm climates that prisumably permitted favourable oil-prone source rock development even in high latitudes, i.e., in North Sea, West Siberia and possibly even Antarctica. • The northwest coast of Australia, favourably located in the Tethyan Realm, continues to contribute important discoveries from North Sea type Jurassic graben situations. • The basic petroleum system in Southeast Asia and East China of graben controlled locustrine source rock development, in early Tertiary time, feeding younger and older reservoirs, continues to account for significant discoveries of both oil and gas in new trapping conditions through the use of 3-D seismic imaging. • The west coast of Africa, from Nigeria south to Angola and the South Asian states of Pakistan, India and Myanmar remain steady, if modest, contributors to world petroleum discovery. • Likewise, in the Middle East, Syria and Yamen serve to broaden the distribution and market availability of petroleum. • The Mediterranean Sea area is filled with a thick sedimentary section sealed by Miocene Messina salt. Owing to deepwater and the low price of oil, only a few exploratory wells have been drilled and the stratigraphy is poorly known. The area has a very complex tectonic history; it is underlain by an unknown amount of oceanic crust and an unknown extension of the African continental platform. SOURCE ROCK • Source rock is defined as a unit of rock that has generated oil or gas in sufficient quantities to form commercial accumulations. • Limited source rock is defined as a unit of rock that contains all the prerequisites of a source rock except volume. • Source rock cannot be defined by geochemical data alone but requires geological information as to the thickness and aerial extent. • Potential source rock is a unit of rock that has the capacity to generate oil or gas in commercial quantities but has not yet done so because of insufficient catagenesis (thermal maturation). • The distinction between source rocks and potential (immature) source rocks are essential in petroleum system studies and when correlating oils to their source rocks. • Active source rock is a source rock that is in the process of generating oil or gas. The distribution of active source rock is essential in petroleum system studies. Active source rock cannot occur at the surface, as they required adequate burial depth to generate oil or gas. 22 • Inactive source rock is a source rock that was once active but has temporarily stopped generating oil or gas prior to becoming spent. Inactive source rocks are usually associated with areas of overburden removal and will generate hydrocarbon again if reburied. • Spent source rock is a source rock that has completed the oil and gas generation process. A spent oil source rock can still be an active or inactive source for gas. source rock potential • The organic origin of oil and gas is now largely undisputed. • Rocks capable of generating and expelling commercial quantities of hydrocarbons must contain elevated levels of organic matter. • The requirement for an elevated level of organic enrichment is due to the need to saturate the source rock pore network with hydrocarbons for expulsion to occur. • A statistical study of fine-grained sedimentary rocks suggests that in order for a rock to be considered organically enriched and a possible hydrocarbon source, it must contain at least 1.0 wt% organic carbon; although this value is greater than that has commonly suggested in the literature. • The richness or petroleum-generating potential of source rock can be determined by measurements of total organic carbon (TOC) and the pyrolysis yield. • Before describing the techniques of measurements of TOC and pyrolysis, let us first look into the organic matter. Diagenesis • Diagenesis is the process of converting living organic material in sediments into kerogene. It involves biological, physical and chemical alteration at temperature upto 50Co (122Fo). It proceeds thermal oil and gas generation which is called catagenesis. Catagenesis • Catagenesis is the process by which organic material in sedimentary rocks is thermally altered, by increasing temperature, resulting in the generation of oil and gas. Catagenesis covers the temperature range between diagenesis and metagenesis, approximating 50Co to 200Co (122Fo to 392Fo). Total organic carbon (toc) • The ability of a potential source rock, to generate and release hydrocarbons, is dependent upon its contents of organic matter, which is evaluated by Total Organic Carbon (TOC). TOC is expressed as weight percent of organic carbon present in the potential source rock. 23 • TOC of a rock is a direct measure of its organic richness. Sufficient quantity of organic matter must be present in a sedimentary rock before it is qualified as a potential source rock for subsequent hydrocarbon generation. • In general, higher the concentration of marine organic matter, the better the source potential. Shales containing less than 0.5% TOC and carbonate with less than 0.2% TOC are generally not considered as a source rock and no further analysis is performed on these samples. • TOC is easy to measure. The dried rock samples are crushed and treated with HCL to remove carbonates. After acid treatment, the sample is subjected to oxidation, so that remaining non-carbonate carbon is converted to CO2 or CO. Pyrolysis • Pyrolysis, from the Greek word Pyro (fire) and lysis (dissolution), is the thermo-chemical decomposition of a substance in the absence of oxygen. • Pyrolysis of rocks, kerogenes and asphattenes form the basis of many laboratory procedures, including Rock-Eval pyrolysis, pyrolysis/gas chromatography, and hydrous or anhydrous pyrolysis. • Through pyrolysis, organic compounds are released in two stages. In the 1st stage free hydrocarbons present in the rock (S1) are released and in the 2nd stage, volatile hydrocarbons formed by thermal cracking are released (S2). • The most widely used equipment is Rock-Eval. It is used to estimate three geochemical parameters: 1. The S1 peak represents the amount of free hydrocarbons at 300Co S1 peak is expressed in my HC/g of rock. 2. The S2 represents the hydrocarbons generated by thermal cracking of kerogene at temperature range of 400-800Co. S2 peak is also expressed in my H/g of rock. 3. The S3 peak represents the amount of CO2 produced from kerogene. It is collected at a temperature range 300-390Co. S3 peak is expressed in my CO2/g of rock. 4. The organic carbon remaining after the recording of the S2 peak, is measured by oxidation under air (or oxygen) atmosphere at 600Co. The CO2 obtained is the S4 peak, which is expressed in mg CO2/g of rock. Note: TOC is computed from peaks S1, S2 and S4.. The Rock-Eval method, used at the well site, is known as Oil Show Analyzer (OSA) divide S1 peak into So peak - which records gaseous hydrocarbon trapped in the rock matrix and which are volatized at 90Co for 2 minutes; and free liquid hydrocarbons, i.e., S1 peak. • The organic matter of sediments is usually divided into bitumen (soluble in organic solvent) and kerogene (insoluble residue). 24 • Bitumen contains free hydrocarbons ranging from C1 to C40, heavy hydrocarbons and NSO’s grouped into resins and alphaltenes. • S1 peak represents hydrocarbons ranging from C1 to C33; whereas heavier hydrocarbons, resins and asphaltenes are minor contributor to S2 peak. • Gaseous hydrocarbons (C1-C7) recorded as the So peak on OSA, are rapidly lost. • In nature, kerogene is progressively cracked during its thermal evolution, generating hydrogen rich hydrocarbons, which may be expelled from the rock; while the residual kerogene is depleted of its hydrogen and becomes more and more condensed untill a sub- graphitic stage is attained, i.e., when no more hydrogen is available. Thus the initial elemental composition of a kerogene determines its ability to generate hydrocarbons. • S2 peak represents most of the hydrocarbons coming from the primary cracking of kerogene, however, it also includes hydrocarbons from the thermo-vaporization and primary cracking of heavy hydrocarbons, resins and asphaltenes. They represent the total amount of oil and gas a source rock can still produce during subsequent complete thermal maturation in an open system. • S2 gives a reasonable evaluation of the current potential of a rock sample i.e., amount of oil and gas which can be generated from its present stage of thermal maturation to the graphite stage. • S2 value depends upon the type of organic matter, the TOC of the sediment and the thermal evolution it has undergone. For immature organic rich sediments, values of 10 to 500 mg HC/g rock were reported. • Coals give S2 peaks ranging from 50 to 500 mg HC/g of rock. It has been noted, through experience, that immature source rocks, which give S2 peaks higher than 5 mg HC/g rocks, can be considered as fair potential source rocks. Note: Pyrolysis of immature organic matter has shown that 70-80% of type I kerogene, 45-50% of type II and only 10-25% of type III kerogene are transformed into hydrocarbons mostly as an S2 peak. • S2 decreases when the thermal evolution of a source rocks increases. • The shape of the S2 peak can also be a useful diagnostic tool, especially when the interpretation of the Rock-Eval parameter is ambiguous. The S2 peak is very narrow and symmetrical for type I organic matter, still symmetrical for type II, but quite wide for type III organic matter. S3 peak - During pyrolysis, oxygen-containing compounds are quickly decomposed into hydrocarbons, water and a mixture of CO and CO2. - Water released from the organic matter cannot be measured in a rock sample due to thermal decomposition of some minerals (such as clays, hydroxides, gypsum etc) too, which generate water. 25 - S3 peak is recorded below 400Co because of the early decomposition of some carbonates, such as, siderite and some other poorly crystallized species. However, calcite and dolomite are decomposed close to 600Co. - S3 depends upon both the type of organic matter and its thermal maturity. It is higher for immature humic type III rocks, but decrease rapidly with an increasing thermal evolution as the oxygenated functional groups (carbonyl, hydroxyl, etc) are easily decomposed. S3 is low for types I and types II kerogene. - When organic matter is already mature (Ro 2%), the 600Co combustion is not complete and S4 peak gives lower value than it should be. Tmax • Tmax is the temperature which is recorded for the maximum of S2 peak, and varies as a function of the thermal maturity of the organic matter. • Mature organic matter, which is more condensed, is more difficult to pyrolyze and requires a higher activation energy i.e., higher temperature. In fact, chemical bonds, that survived in most highly mature kerogenes, are those which require higher energy to be broken. • Tmax is linked to the kinetics of the cracking of organic mater. Types I and type II kerogenes are known to have relatively simpler molecular structures than type III. It requires a narrower distribution of cracking activation energies and a smaller temperature range. • An example of correlation between Vitrinite reflectance and Tmax is given in the chart. • Anomalous values of Tmax were found for organic mater associated with high uranium content due to local radiolysis. • Tmax is a good maturation index for type II and type III organic mater. In most cases, the oil window is attached for values around 435Co. Except for type II-S for which it begins around 420Co. • The gas/condensate window is reached at 450Co for Type I organic matter, 455Co for Type II and 470Co for Type III. The dry gas window is attained at 540Co for Type III. • Tmax should be represented in a vertical log as a function of depth in order to visualize its slow increase with depth and to eliminate abnormal values. • Tmax is also a powerful tool to detect pollution by drilling fluids and natural impregnation of hydrocarbons, either migrating or trapped in a reservoir. In such cases Tmax is abnormally low. Hydrogen Index (HI) • Hydrogen index is an important calculated parameter that helps to define whether a sample is oil prone, mixed oil and gas prone. • Hydrogen index corresponds to the quantity of hydrocarbon generated relative to the total organic carbon (TOC). Hydrogen index is not computed if TOC is <0.5% wt. • Hydrogen index is defined as the ratio between S2 (expressed in mg HC/g rock) and TOC (expressed as weigh percent). 26 HI = S2/TOC (expressed as mg HC/g TOC) • In the interpretation of hydrogen index data, following guidelines are used: HI = (S2/TOC) x 100 • Gas prone sample is represented through the HI range from 0-200, mixed oil and gas through 200-300, and oil more than 300. • Oxygen index is defined as the ratio between S3 (expressed in mg CO2/g rock) and TOC (expressed as weight percent). OI = S3/TOC (expressed as mgCO3/g TOC) • A good correlation was found between H/C of kerogen, measured after acid treatment of the rock matrix, and their hydrogen index measured by the Rock-Eval pyrolysis of the rock sample. • This correlation exists for all types of organic matter and for all stages of thermal maturation, with the exception of, however, immature peats and lignites, which have a high oxygen/carbon ratio. • For peats and lignites a large proportion of hydrogen is combined as hydroxyl group (OH). This hydrogen is latter transformed into water and does not participate in the genesis of oil. • Pyrolysis of kerogene and coal show a fair correlation between OI and O/C ratio, although some oxygen is lost as water and does not contribute in S3 peak. • Diagrams of HI vs OI are currently used (Fig. 10) for kerogene types evaluation instead of conventional Van Krevelen diagrams obtained on kerogenes isolated from their rock matrix by acid treatment. • For each type of organic matter, an evolutionary pathway trajectory can be defined from the immature stage down to the sub-graphitic stage in which almost all hydrogen and oxygen have been lost (Fig. 10). • It can be seen from the figure 10, that evolutionary pathways are almost vertical for Type I and Type II kerogenes for which only a small amount of oxygen is lost at the beginning of the thermal evolution, while coals and type III kerogenes show a strong decarboxylation before they are able to generate hydrocarbons. Another evolution diagram can be drawn by comparing the evolution of the hydrogen index of different kerogenes as a function of their thermal evolution assessed by their Tmax (Fig. 11). It can be seen from the figure that for type I kerogene, the depletion of hydrogen is very rapid, corresponding to a small range of Tmax. Almost only liquid hydrocarbons are generated, and if they are expelled from the source rock, very little amount of gas is generated. For type III, depletion of hydrocarbon is progressive. Sample Collection • The quality of any geochemical interpretation as well as its significance is determined directly by the quality of the samples and the initial design of the sampling program. • Geochemical data may be obtained on numerous types of samples, including outcrop, cuttings, cores, seeps, produced oil and gases. 27 • No single sample can effectively represent all of the geochemical attributes associated with a hydrocarbon source rock system. Significant differences have been observed in the level of organic enrichment, hydrocarbon generation potential and organic matter type, as indicated by Hydrogen Index, between individual samples. Such organic geochemical variations are consistent with the variability in the lithofacies itself. • Because of both the stratigraphic and lateral variability, observed in source rocks, sampling programs need to incorporate both random sampling and channel (composite) sampling. • Channel sampling provides a more representative overview of the source potential of a formation or interval; however, the better source intervals may be effectively diluted. • The channel sampling approach is most appropriate when one is attempting to correlate an oil to a specific source because oils represent an integrated product. • From subsurface samples, source rock potential cannot be adequately assessed if the well has been drilled using an oil-based mud. The situation results in anomalously high generation potentials because of hydrocarbon contamination. • Caving can also result in problems. Specially caving may result in the dilution of source rock intervals and at the same time an over-estimation of possible source rock thicknesses if the caved material represents coaly intervals and an underestimation of the absolute level of thermal maturity. • Unlike subsurface samples, outcrop sample quality may be highly variable due to weathering. Surface weathering tends to result in oxidation, which reduces a samples level of organic enrichment, total generation potential and apparent oil-proneness. It may also influence the observed level of thermal maturity (Fig. 12). • It is, therefore, important that the freshest samples be obtained for analysis. • When sampling oil and gas, every attempt should be made to obtain samples from discrete producing horizons. In fact in basins with multiple sources and multiple pay zones, the use of combined fluids may result in a completely inaccurate interpretation of the sample’s hydrocarbon generation and migration history. KEROGE • Kerogens are chemical compounds that comprise segment of organic matter in sedimentary rocks, insoluble in the normal organic solvents because of their huge molecular weight (more than 1,000). The soluble portion is known as bitumen. • Each kerogene molecule is unique because it is formed by the random combination of numerous monomers. • Kerogens are the precursors to hydrocarbons (fossil fuels) and are also the material that forms oil shale. Maturity 28 • In petroleum geology, the maturity of a rock is a measure of its state in terms of hydrocarbon generation. • Maturity is established using a combination of geochemical and basin modeling techniques. • Organic rich rocks (termed source rocks) will alter under increasing temperature such that the organic molecules slowly mature into hydrocarbons. • Source rocks are broadly categorized as immature (no hydrocarbon generation), sub-mature (limited hydrocarbon generation), mature (extensive hydrocarbon generation) and overmature (most hydrocarbon have been generated). • The maturity of a source rock can also be used as an indicator of its hydrocarbon potential. For example, if a rock is sub-mature, then it has a much higher potential to generate further hydrocarbons than the one that is overmature. • Aquatic and terrestrial organic matter, that is preserved in sediments, is converted to kerogene by biological and very low temperature processes termed diagenesis. • As sediments are more deeply buried, kerogene is converted into oil and gas by thermal processes, known as catagenesis. Under extreme thermal stress, organic matter is meta- morphosed into methane and graphite by a process, called metagenesis. • Changes in physical and chemical properties of organic matter can be used to determine the degree of transformation that has taken place. This is important to petroleum geochemists because it tells them whether or not oil and gas have been generated in the source rocks. • A large number of techniques have been developed to determine the degree of thermal evolution, or maturity, of organic matter in sedimentary rocks. These include gas chromatography and biomarkers (gc/ms) analysis on the solvent extractable organic matter (bitumen) and Rock-Eval pyrolysis, pyrolysis-gas chromatography and kerogene microscopy on the insoluble organic matter (kerogene). • Bitumen maturity analysis is, however, often not reliable because of the ease with which hydrocarbon liquids can migrate and thereby contaminate the sample being analyzed. For this reason, methods of measuring kerogene maturity provide the most reliable data. • Rock-Eval pyrolysis is the most common kerogene maturity screening technique used by the petroleum industry. When organic matter is heated upto a temperature of 550Co, in the absence of oxygen, it breaks down or pyrolyzes into hydrocarbons that can be detected by a Rock-Eval pyrolyzer. • The temperature, at which the maximum rate of thermal degradation occurs, is called Tmax. Tmax temperatures range from 435Co to 450Co for source rocks in the oil generation zone. These temperatures are considerably higher than natural oil generation temperatures (100- 130Co), but can be calibrated to natural generation processes. • Kerogene microscopy can measure the change in colour in transmitted light of organic matter as it matures. Colour changes from yellow to amber to brown and finally to black are calibrated accurately to numerical colour scale, the most common of which is TAI (Temperature Alteration Index). Oil is generated when organic matter becomes amber at a TAI value of 2. • The most commonly used and accurate kerogene maturity technique is Vitrinite reflectance. 29 • Vitrinite is a coal maceral whose reflectivity increases systematically with maturity and can be measured very accurately with reflecting light microscopy. Oil is generated between 0.6 and 1.0 Ro, which is the percent of incident light reflected when viewed with an oil immersion objective. • Although Vitrinite reflectivity has nothing directly to do with oil generation, it can be calibrated accurately to oil and gas generation processes. • Kerogene maturity data can also be used to estimate the amount of section lost at unconformities, including the present land surface, the proximity to igneous intrusions, the throw (vertical displacement) of faults, the provenance of sedimentary debris, the location of present or past overpressured zones, and many other events of interest to geologists. • Maturity also can be measured by a host of other techniques, each of which has its unique strengths and weaknesses. It is always best to use several techniques to determine kerogene or bitumen maturity and to use experienced laboratories familiar with many pitfalls that can affect the analytical results. • A trap that is formed after a source rock became inactive for example will not contain oil or gas generated from that source rock even though geochemical data appear favourable. Thermal maturity and hydrocarbon generation • Presence of a hydrocarbon source rock is insufficient to insure that hydrocarbon generation will occur. Organic-rich units must undergo a favourable burial/thermal history in order for the kerogenes to be broken down into mobile phase. • Conversion from kerogene to bitumen, bitumen to oil and ultimately oil to gas is manifested by a series of physical and chemical changes in both the kerogene and bitumen phases. • The most commonly utilized indirect measure of thermal maturity is change in vitrinite reflectivity. Vitrinite reflectance increases with increasing thermal maturity (Fig. 13). • Mean vitrinite reflectance data, typically based on between 50 and 100 individual reflectivity measurements, are commonly plotted as a function of depth on semi-log paper (Fig. 14). • A normal profile is typically linear, representing continuous sedimentation and permits the identification of the top and base of each individual hydrocarbon generation and preservation zone. • Vitrinite reflectance profile, however, often deviates from this ideal linear character. There are several analytical and geologic reasons for such deviations. • Analytically, there may be problems with the identification of true vitrinite. For example, if solid bitumens are misidentified as vitrinite, the mean reflectance value would appear to be anamalously low. • Another analytical complication may arise when there is an association of indigenous primary vitrinite population as well as more mature recycled vitrinite and/or less mature vitrinite, that is associated with caved cuttings. 30 • In addition to the above noted analytical and sample problems, there are some geologic causes too for nonlinearity in vitrinite reflectance profiles. • One such cause is the presence of intrusives in the stratigraphic section. The presence of these intrusives results in significant high levels of thermal maturity these effects are largely localized and reflect contact metamorphism. • An offset and an apparent decrease in thermal maturity with depth may result as a consequence of thrust faulting. • One of the most commonly cited reasons for discontinuous and nonlinear vitrinite reflectance profiles is the presence of an unconformity. It has been suggested that the displacement in the vitrinite reflectance profile can be used to estimate the amount of missing section at the unconformity. • Another geologic cause of an offset in the reflectance profile is a marked change in lithologic character, which in turn is associated with large contrasts in thermal conductivity within the sedimentary column. For example, coal is a poor conductor and thus allows a build-up of “excess” heat in the lower portion of the well. It is this excess heat that results in the elevated levels of thermal maturity. • Note: Although vitrinite is the most commonly used thermal maturity index, it is, however, stratigraphically limited to post-Silurian units, because of absence of woody land plants prior to the Devonian. In addition, vitrinite is generally lacking in sandstones and carbonate rocks and when present is poorly preserved. • When vitrinite is absent or poorly preserved, other indirect measures of thermal maturity, such as TAI and colour changes in conodonts, are utilized. • Thermal alteration index (TAI) technique is based on colour changes of spores and pollen grains in transmitted light or changes fluorescence colour and intensity in reflected light. Although considered somewhat less accurate and more variable, TAI may be estimated using amorphous kerogene. • NOTE: All the above-mentioned various thermal maturation indices can be correlated with each other. 31 Source rock maturity summary Immature Source Rocks: Tmax <435Co Ro<0.65% Overmature Source Rock: Tmax >450Co Type I Tmax >465Co Type II Tmax >540Co Type III Oil Window: Ro = 0.65 to 1.3% Tmax 440 to 450Co for Type I organic matter Tmax 435 to 460Co for Type II organic matter Tmax 420 to 460Co for Type IIS organic matter Tmax 435 to 470Co for Type III organic matter Gas and Condensate: 470Co to 540Co Type III. Dry gas: Ro >1.6% Tmax >540Co Type III. Transformation ratio • Transformation ratio is the ratio of free hydrocarbon to total pyrolyzable hydrocarbon i.e. S1/S1 + S2. • Elevated transformation ratio values, associated with depressed Tmax values, are indicative of the presence of nonindigenous (contaminated) organic matter. Preservation of organic matter • Initial oxygen solubility is important, because lower initial oxygen concentration are more easily depleted leading to higher levels of organic preservation. • Oxygen slubility decreases with increasing temperature and increasing salinity. Because of these relationships, warm saline waters have a greater potential to develop anoxic conditions than cooler fresh waters. In fact, warm saline bottom waters have been used as one explanation for the widespread development of the organic-rich Cretaceous sediments. • One can anticipate then that enhance levels of preservation would be favoured at low latitudes, where water temperatures are elevated and evaporation is greater then precipitation. • Secondary oxidizers, such as, sulphate, may play a major role in organic matter degradation, particularly in evaporitic settings. For example, within solar Lake in Sinai, over 90% of the organic matter produced is degraded through sulphate reduction. Thus, preservation would be favoured in environments where sulphate concentration were minimized. • In addition to the presence of biologic and chemical oxidizing agents, which may influence both the quality and quantity of preserved organic matter, the time of exposure within the water column, is a function of water depth and settling rate. 32 • Within oxygenated basins the degree of preservation is inversely proportional to the water depth, i.e., there is decreased preservation efficiency with water depth. Thus the idea that source quality also improves in a more basinal position is not always the case, and is probably only valid if much of the water column is anoxic or dysaerobic. • Settling rate is a function of the relative densities of the particle and the media through which it is settling and the particle size. In general, in order to achieve settling rates sufficient to preserve organic matter, within an oxygenated water column, the material must be incorporated into pellets by various zooplankton. HYDROCARBO MIGRATIO • It is rare that a hydrocarbon source rock also acts a reservoir. These rare exceptions are associated with fracture production from such units as the Austin Chalk (Texas), the Bakken Shale (North Dakota) and the Monterey Formation (California). • The process through which hydrocarbons move from the source to the reservoir is termed migration. • Hydrocarbon migration can be viewed as a two-step process: (1) primary migration i.e., movement of hydrocarbons from the source rock into the carrier network, and (2) secondary migration, i.e., redistribution of hydrocarbons within the basin. • Depending upon the geologic setting, hydrocarbon movement may be either dominated by lateral (bed parallel) or vertical components. • Bed parallel migration dominates in settings lacking major faults and diapiric provinces. It permits the collection of hydrocarbons over very large regions and allows for the presence of significant quantities of hydrocarbons outside the limit of the generative basin. • In contrast, vertical movement of fluids dominate in highly faulted systems and systems with major diapiric activity. In such systems the hydrocarbons are usually restristed to the areal extent of the generative portion of the basin, and there are numerous multiplay fields. • In the bed parallel case hydrocarbon flow, in the simplest terms, can be consider updip. The nature of the flow determines how effective the migration process is in collecting and concentrating the hydrocarbons within a basin. • The hydrocarbons will be either focused (concentrated) or dispersed. Migration is focused when a large generative region has its hydrocarbons concentrated into a small region. Focused migration typically occurs within a basin where a structural high is largely surrounded by a generative basin. Such conditions increase the overall prospectiveness of a region. • In contrast, where there is a small generative region charging a large portion of a basin, the flow is considered to be dispersive. Dispersive migration is common when generation takes place in a structural low and prospective traps are positioned around the basin flanks. Under these circumstances, although the quantity of the hydrocarbons generated may be quite high, the volume of hydrocarbons, reaching any individual trap, is generally small. Such conditions, therefore, decrease the overall prospectiveness of a region. 33 • The migration patterns are based on structural considerations and will be modified by the character and continuity of the carrier system. Common carrier systems include porous sands (sheets and lenses), fracture systems, bedding planes, partings and unconformities. • Hydrocarbon flow will be diverted to those regions, which offer the least resistance (i.e., the greatest porosity and permeability). • In the tertiary basins, where hydrocarbon generation has only recently occurred, hydrocarbon flow directions can commonly be established using the present structural configuration. • In older Mesozoic and Paleozoic basins, where considerable time has passed since the hydrocarbon generation, the present structural configuration may not reflect the patterns of hydrocarbon flow during active generation. In such situations, it is necessary to construct the basin’s geometry during the time of generation. • Bed parallel migration distances are largely limited by lateral carrier continuity appears to be limited by structural considerations, e.g., in rift basins, maximum migration distances are on the order of tens of miles; whereas, in foreland basins, migration distances may be on order of hundreds of miles. • Migration is ultimately terminated when the buoyant force is incapable of pushing the petroleum column through the pore network. This usually involves a facies change (i.e., stratigraphic trap) or an increase in the amount of pore-filling cement (i.e., diagenetic trap). • The presence of disruptive faults and/or diapirs result in a shift from bed parallel to vertical migration. Such situations explain the many cases where reservoirs and sources are disassociated. The vertical flow may actually occur through a permeable rubble zone associated with these structural features. • The rate of migration is a function of several independent factors, including API gravity (buoyancy), in situ hydrocarbon viscosity, effective porosity and permeability and the dip of the carrier system. Migration rate increases with increasing API gravity, porosity, permeability and dip and decreases with increasing viscosity. • Therefore, the rate of hydrocarbon movement may play a role in foreland basins, where regional dips are low and migration distances may reach sever hundred miles. Rate does not appear to be important in rift settings where migration distances are only on the order of several tens of miles. RESOURCE ASSESSME T • The ultimate aim of basin evaluation process is the estimation of the quantity of hydrocarbons available for entrapment. • The approach specifically addresses the estimation of oil-in-place, and does not address gas quantifications, which may introduce substantial errors into the calculation (e.g., gas solubility, diffusion etc). • The amount of oil available for entrapment actually represents only a small percentage of the generative potential. The potential quantity of oil is reduced by the lack of generation (level of thermal maturity), the retention of hydrocarbons by the source rock (expulsion 34 efficiency), the retention of hydrocarbons in the carrier network (residual hydrocarbons), the loss of hydrocarbons from the system by breaching of a trap, the bypassing of a trap, displacement of oil by gas, and the generation and migration of hydrocarbons prior to trap development. • Ideally each of these components should be addressed individually; however, sufficient information for such an analysis is not presently available, even in the more mature exploratory provinces. • It is, therefore, has been assumed that the amount of oil entrapped can be represented by a percentage of the oil-like (C15+) hydrocarbons in the source system. This percentage is termed the basin’s efficiency factor. • At the present time, the assignment of an efficiency factor is semiquantitative at best. Empirical data suggests the efficiency factors range from less than 1% in the Paris basin to approximately 35% in the Los Angeles basin. • The quantity of hydrocarbons, present in the source rock system, can be estimated in either of three ways. • The first method is based on the direct measurement of C15+ hydrocarbons, within generative basin. These values may be obtained either through extraction and gravimetric analysis or through pyrolysis. If determined through pyrolysis, the S1 values can be equated to C15+ hydrocarbons. ote: Unfortunately, samples of mature source rock, within the generative portion of the basin, are usually not available and if available are not available in sufficient quantities or with the necessary geographic distribution to be considered representative of the generative basin. • The other two approaches utilize information from the immature portions of the basin to estimate the quantity of hydrocarbon present within the generative portion of the basin. • One of these approaches utilizes the empirical relationship between the level of thermal maturity (observed or calculated) and the transformation ratio, as defined by pyrolysis. This method is limited to samples that have not matured beyond the oil-window. This method is not appropriate for more elevated levels of thermal maturity, because the ratio does not take into consideration either the gas or gasoline-range hydrocarbons which form as a result of thermal digradation of heavier hydrocarbons. • The third approach estimates the amount of hydrocarbons through a kinetic model of hydrocarbon generation (Sweeney et al., 1987). This requires information on the burial and thermal history of the source rock, the level of organic richness and the kinetic constants associated with the source rock. More often, kinetic constants used in these calculations, represent published values for the appropriate ‘kerogene type’ rather than values obtained for the specific source rock system under evaluation. ote: It is important to note that variations in these parameters may have a significant impact on the calculated volumes of hydrocarbons generated and the timing of generation (Fig. 15). 35 • Unlike the empirical correction for thermal maturity, the use of the kinetic model permits to estimate the amount of heavy liquids (i.e., petroleum) remaining even within the more thermally mature portions of the basin. This is possible because these models take into consideration the thermal degradation of oil into gas. • The volume of source rock is determined by defining the areal distribution of the generative basin and the net source rock thickness. • The net source rock thickness is used, rather than the gross source rock thickness, to account for the variability observed within many formations. • The area determination may incorporate the entire basin if the total regional resource potential is being determined, or just a portion of the basin representative of an individual generative prism if individual prospects are being evaluated. HYDROCARBO GEOCHEMISTRY • As described earlier, source rocks are not always identified and sampled, and modeling may be used to predict the nature and distribution of possible sources within a basin (Seifert et al., 1984). The chemistry of both oils (produced and seeps) and gases may be used to test and constrain these geochemical models. Oil Geochemistry • Oils are complex mixture of a wide variety of compounds, including both hydrocarbon and nonhydrocarbon components (Figures 16 and 17; Tissot and Welte, 1984). • The relative abundance of various compounds as well as the presence of specific compounds can provide substantial amounts of information on the nature of the source rock system, the degree of alteration, and possibly the level of maturity of the system. These data may also provide information as to the number of different sources present within the generative basin. • Bulk oil chemistry provides a classification scheme, which has a bearing on both its origin (nature of the source rock system) and producibility (Fig. 18). • There are six primary types of crude oils: 1. Parafinic crudes are associated with nonmarine environments. Their source is commonly locustrine. Although the waxiness of many of these crudes is thought to be a result of higher land plant input (cuticle, spores and pollen), they may also an algal precursor (Fig. 19). 2. Paraffinic-naphthenic or aromatic intermediate crudes are usually generated from marine organic matter. 3. The remaining classes, naphthenic, aromatic-naphthenic and aramatic-asphallic are believed to be derived from various biochemical and physicochemical alternation processes of the other three oil classes. 36 Note: In general, altered crudes are depleted in both the normal and branched chained (isoprenoids) paraffins as a result of bacterial processes (Fig. 20). • The extent of biodegradation is in part controlled by reservoir temperature. • Various biodegradational processes result in the alteration in various physical and chemical parameters of the crude oil (Fig. 21) including an apparent enrichment in the nonhydrocarbon components (i.e., resins and asphaltenes). Higher concentrations of resins and asphaltenes result in a reduction in API gravity and an increase in viscosity. • The quantity of sulfur may provide information on the nature of the source rock system. In general, high sulfur (S>1.0 wt.%) crudes occur more frequantly in carbonate-evaporitie sequences than in clastic sequences. This is due to availability of iron in clastic system, with which sulfur form such minerals as pyrite (Fig. 22), thus preventing its incorporation into the kerogene and ultimately in the crude oil. • Elevated sulfur concentration may also reflect biodegradation as a result of hydrocarbon depletion. • Crude oil Nickel/Vanadium ratios are also believed to provide information on the nature of the source rock depositional environment. High Ni/V (>10) ratios are indicative of alkaline lacustrine environments; moderate (1-10) ratios are typical of acidic lacustrine settings, while low (<1) ratios are typical of marine environments (Lewan, 1984). • Enriched levels of these metals (concentrations > 100 ppm) are observed in bitumens and crude oils derived from type I and type II kerogenes. Concentrations of less than 100 ppm are associated with bitumens derived from type III organic matter. The elevated levels of enrichment appear, therefore, to be associated with conditions that favour preservation of algal material (Lewan and Maynard, 1982). • The n-alkanes (Fig. 23) are derived from plant, bacterial and algal lipids. Terrestrial plants, because of the waxes that coat leaves, seeds, pollen and spores, tend to display n-alkane distributions skewed toward the higher carbon numbers compared to that produced by either marine algae or bacteria (Fig. 24). • Many sediments receive contributions from both terrestrial and marine sources and therefore display a mixed n-alkane distribution. • It has been observed that no single compound, ratio or index should be used to establish the nature of the source rock system, and that all of the available data should be examined collectively. In addition, it must also be understood that many of these environmental indicators may be altered by maturation, migration and biodegradation. Gas Geochemistry • Carbon isotopic composition of the methane provide some information on the minimum level of thermal maturity of the source. This information, when used along with the thermal maturity information obtained on possible sources, may then be used to place the gas source stratigraphically (Fig. 25). Correlation Studies 37 • Correlation studies, including oil-to-oil and oil-to-source rock, provide additional information which can aid in the development of an exploration strategy. • Such studies provide information on the number of possible sources and the probable migration pathways within a basin, which may ultimately lead to the identification of new exploratory targets. PETROLEUM SYSTEM Introduction • Sedimentary basins, petroleum systems, plays and prospects can be viewed as separate levels of investigation, all of which are needed to better understand the genesis and habitat of hydrocarbons. • Sedimentary basin investigations emphasize the stratigraphic sequence and structural style of sedimentary rocks. • Petroleum system studies describe the genetic relationship between a pod of active source rock and the resulting oil and gas accumulations. • Investigations of plays describe the present day geologic similarity of a series of present traps. • Studies of prospects describe the individual present day trap. • Essential elements are source rock, reservoir rock, seal rock and overburden rock. • Processes include trap formation and the generation-migration-acumulation of petroleum. • All the essential elements must be placed in time and space such that the processes required to form a petroleum accumulation can occur. • Economic considerations are unimportant in sedimentary basin and petroleum system investigations, but are essential in play and prospect evaluation. • A prospect is conceptual because a successful prospect turns into an oil and gas field when drilled or disappears when the prospect is unsuccessful. • Prospect modeling is carried out on a prospect to justify drilling, whereas a prospect analysis is carried out after drilling to understand why it lacked commercial hydrocarbons. 38 Sedimentary basin investigations • Over the last several decades, investigations of sedimentary basins have emphasized plate tectonics or structural evolution. With passage of time new approaches, to the analysis of petroliferous sedimentary basins, become more focused on the genesis of petroleum as merely sedimentary basin type does little to improve our ability to forecast the volume of petroleum from a particular type of basin. • As more petroleum geochemistry is incorporated into the analysis of a sedimentary basin, the success ratio goes up and the forecast of petroleum occurrence becomes more certain (Tissot et al; 1987). • When sedimentary basins, with uncomplicated geologic histories, are studied, a basin analysis approach that promotes organic geochemistry works well. However, when similar studies are carried out in fold and thrust belts, or in areas of uncommon heat source (such as in the mid-pacific ridge), basin analysis techniques are more difficult to apply because the original sedimentary basin is severely deformed or incomplete. • A sedimentary basin analysis investigates the formation and contents of this depression. Structural and stratigraphic studies are the most conventional way to study a sedimentary basin. More recent techniques include seismic stratigraphy and sequence stratigraphy. Sequence stratigraphy, e.g., can be used to understand the distribution of sandstone and shale in a particular area as a package of related sedimentary rock. For the petroleum geologist, in certain areas the reservoir properties of this sandstone can be mapped as well as the organic facies of the shale. Petroleum System Investigations • Each investigative procedure has an appropriate starting point. For the prospect analysis, the starting point is the trap, for the play, a series of traps, and for a basin analysis, a tectonic setting and sedimentary rocks. • Similarly, the investigative procedure for the petroleum system starts with discovered hydrocarbon accumulation, regardless of size. After the system is identified, the rest of the investigation is devoted to determining the stratigraphic, geographic and temporal extent of the petroleum system. • The bigger the petroleum system, the more likely it will have generated and accumulated commercial quantities of hydrocarbons. • Petroleum system defines a level of investigation that usually lies between that of a sedimentary basin and a play. Play and prospect investigation • Beyond sedimentary basin and petroleum system analysis, the remaining levels of investigation are play and prospect analysis. • Plays and prospect definition includes present-day exploration potential for undiscovered commercial oil and gas accumulation. Presence of reservoir rock, seal rock, trap volume, hydrocarbon charges and timing is usually involved in this evaluation. 39 Petroleum system • A petroleum system is defined here as a natural system that consists of a pod of active source rock and all related oil and gas and which includes all the geologic elements and processes that essential if a hydrocarbon accumulation is to exist. • A petroleum system exists wherever the essential elements and processes occur. Characteristics and Limits • The geographic, stratigraphic, and temporal extent of a petroleum system is specified and is best depicted using a table (Fig. 26) and the four figures (Figs. 27-30). 1) A burial history chart (Fig. 27) showing the critical moment, age and essential elements at a specified location. 2) A map (Fig. 28) showing the geographic extent of the petroleum system at the critical moment (250 ma), 3) A cross section (Fig. 29) drawn at the critical moment depicting the spatial relationship of the essential elements, and 4) A petroleum system events chart (Fig. 30) showing the temporal relationship of the essential elements and processes and the preservation time and critical moment for the system. • A critical moment is that point in time, selected by the investigator, that best depicts the generation-migration-accumulation of most hydrocarbons in a petroleum system. A map or cross section, drawn at the critical moment, best shows the geographic and stratigraphic extent of the system. • If properly constructed, a burial history chart shows that time when most of the petroleum in the system is generated and accumulating in its primary trap. • For biogenic gas, the critical moment is related to low temperatures. • Geologically, generation, migration and accumulation of petroleum, at one location, usually occur over a short span of time. • Essential elements, when included with the burial history curve, show the function of each rock unit and lithology in the petroleum system. In the example of Figure 27 (using the fictitious rock units), the Deer Shale is the source rock, the Boar Sandstone is the reservoir rock, the George Shale is the seal rock, and all the rock units above the Deer Shale comprise the overburgen rock. The burial history chart is located where the overburden rock is thickest and indicates that the source rock started through the oil window 260 Ma in Permian time (time scale from Palmer, 1983) and was at its maximum burial depth 255 Ma. The critical moment is 250 Ma, and the time of generation, migration and accumulation ranges from 260 to 240 Ma, which is also the age of the petroleum system. • The geographic extent of the petroleum system, at the critical moment, is defined by a line that circumscribes the pod of active source rock and includes all the discovered petroleum shows, seeps, and accumulations that originate from that pod. A plan map, drawn at the end of Paleozoic time in our example (Fig. 28), includes a line that circumscribes the pod of active source rock and all related discovered hydrocarbons. 40 • Stratigraphically, the petroleum system includes the essential elements within the geographic extent, i.e., a petroleum source rock, reservoir rock, seal rock and overburden rock at the critical moment. The functions of the first three rock units are obvious; however, the function of the overburden rock is multiple, as in addition to proding the overburden necessary to thermally mature the source rock, it can also have considerable impact on the geometry of the underlying migration path and trap. The cross-section of Figure 29), drawn to represent the end of the Paleozoic (250 Ma), shows the geometry of the essential elements at the time of hydrocarbon accumulation and best depicts the stratigraphic extent of the system. • The petroleum system events chart shows eight different events (Fig. 30). The top four event record the time of deposition from stratigraphic studies of the essential elements, and the next two events record the time the petroleum system processes took place. The formation of traps is investigated using geophysical data and structural geologic analysis. The generation- migration-accumulation of hydrocarbons, or age of the petroleum system, is based on stratigraphic and petroleum geochemical studies and the burial history chart. These two processes are followed by the preservation time, which takes place after the generation- migration-accumulation of hydrocarbon occur, and is the time when hydrocarbons within the petroleum are preserved, modified, or destroyed. • When the generation-migration-accumulation of the petroleum system extends to the present day, there is no preservation time, and it would be expected that most of the petroleum is preserved and that comparatively little has been biodegraded or destroyed. • The last event is the critical moment as determined by the investigator from the burial history chart, and it shows the time represented on the map and the cross-section. Level of certainty • A petroleum system can be identified at three levels of certainty: known, hypothetical, or speculative. The level of certainty indicates the confidence for which a particular pod of active source rock has generated the hydrocarbons in an accumulation. • In a known petroleum system, a good geochemical match exists between the active source rock and the oil or gas accumulations. • In a hypothetical petroleum system, geochemical information identifies a source rock, but no geochemical match exists between the source rock and the petroleum accumulation. • In a speculative petroleum system, the existence of either a source rock or petroleum is postulated entirely on the basis of geologic or geophysical evidence. Pod of Active Source Rock • A pod of active source rock indicates that a contiguous volume of organic matter is creating petroleum, either through biological activity or temperature, at a specific time. • The volume or pod of active source rock is determined by mapping the organic facies (quantity, quality and thermal maturity) considered to be the presently active, inactive or spent source rock using organic geochemical data displayed as geochemical logs (Fig, 31). 41 • Organic matter generates petroleum either biologically or thermally. From the time a petroleum phase is created, a petroleum phase exists. A source rock is active when it is generating this petroleum, whereas an inactive or spent source rock was at some time in the past an active source rock. For example the Deer Shale source rock was an active source rock in Late Paleozoic time, but is presently an inactive source rock. The active time can be present day or any time in the past. Petroleum • As used in this volume, the terms petroleum, hydrocarbons and oil and gas are synonyms. Petroleum originally referred to crude oil, but its definition was broadened by Levorsen (1967) to include all naturally occurring hydrocarbons, whether gaseous, liquid or solid. • Geochemically, hydrocarbon compounds are those containing only hydrogen and carbon, such as aromatic or saturated hydrocarbons. • Hydrocarbon and non-hydrocarbon compounds are both found in crude oil and natural gas, but hydrocarbon compounds usually predominate. • Condensate is in gas phase in accumulation and in a liquid at the surface, but either way it is considered petroleum, as are solid petroleum material, such as, natural bitumen, natural asphalt and bituminous sands. Preservation time • Preservation time of petroleum system starts after oil and gas generation, migration and accumulation processes are complete. • Processes that occur during the preservation time are remigration, physical or biological degradation and/or complete destruction of the hydrocarbons. • During the preservation time, remigrated petroleum can accumulate in traps formed after hydrocarbon generation has ceased in the petroleum system. • If insignificant tectonic activity occurs, during the preservation time, accumulation will remain in their original position. • Remigration occurs during preservation time only if folding, faulting, uplift or errosion occurs. • If all accumulations and essential elements are destroyed, during the preservation time, then the evidence that a petroleum system existed is removed. • An actively forming or just completed petroleum system is without a preservation time. Investigative technique • A petroleum system investigation should begin with hydrocarbons, such as, show of oil and gas. In the same way as sedimentary rock requires a sedimentary basin, an oil or gas show requires a petroleum system. • The smallest accumulation of show give cluse that commercial accumulations are possible. 42 • Petroleum system investigation approach requires the focus on work on the stratigraphic and structural studies of the essential elements and processes. • Ideally, a petroleum system analysis begins with an oil and gas show map. Geochemical analysis of those hydrocarbon shows are needed to understand the origin of the oil or gas (biogenic versus thermal). • Comparing oil to oil and gas to gas can indicate whether more that one petroleum system is involved. • The line of inquiry can be expanded to include the type of organic matter responsible for those shows and the overburden rock required to thermally mature the source rock. • To determine the geographic, stratigraphic, and temporal extent of the petroleum system, the investigator will need to acquire specific information to make the burial history chart, map, cross-section and events chart that define the system (Figs. 27-30). • There are some limitations on the oil-oil and oil-source rock correlation. First, if two oils are identical, they may not necessarily be in the same petroleum system, even though the oil- source rock correlations indicate that they are from the same source rock. • Secondly, if two oils are different, they may still can be from the same source rock. For example, if the organic facies changes within a pod of active source rock, the oil may be from the same petroleum system. • Finally to identify a petroleum system uniquely the extent of hydrocarbon shows must be mapped relative to the pod of active source rock. OVERBURDE ROCK (Temperature and Heat Flow) Main features • Overburden rock, an essential element of the petroleum system is the sedimentary rock that overlies the source rock, seal rock and reservoir rock. • Generation of hydrocarbons, from thermal degradation of organic matter in the source rock, is determined by thickness of the overburden rock in conjunction with the physical properties and processes that determine temperature in sedimentary basins. • Source rock temperature is largely determined by thickness and thermal conductivity of the overburden rock, heat flow and ground surface temperature. • Processes, such as, groundwater flow and sedimentation may also have significant effects on the thermal regime. 43 Introduction • Overburden rock, based on volume, is usually the largest part of the basin fill. It overlies the source rock, seal rock and reservoir rock i.e. the three other essential elements, and in some situations, these three elements may also be part of the overburden rock. • The underburden rock constitute the remainder of the basin fill i.e. sedimentary rock that lies between the basement rock and the essential elements of the petroleum system. • The overburden rock affects a number of physical processes, which are important to the petroleum system. Because of burial, a source rock generates petroleum, a reservoir rock experiences a loss of porosity through compaction, a seal rock becomes a better barrier to petroleum migration, and if oil and gas are kept in a trap at an optimum temperature, biodegradation is prevented. • The time sequence, in which the overburden rock is deposited, affects the geometry of the interface of the source rock and the overburden rock, and of the seal rock and reservoir rock. Thus, the geometry of the source-overburden horizon influences the timing and direction of petroleum migration, and the seal-reservoir horizon dictates the timing and effectiveness of trap formation. • In this way, the overburden rock is important to the generation, migration and accumulation of petroleum and to the formation of traps that contain petroleum. • Here we will be discussing only the key role of the overburden rock in determining the thermal evolution of the source rock. • To acquire the temperatures for oil and gas generation, a source rock must be buried by overburden rock through the process of sedimentation. • The extent, depth and timing of hydrocarbon generation from the source rock thus depend on the sedimentation rate and the geothermal gradient. For a typical geothermal gradient of 25Co/km, most oil generation takes place at depths of about 3-6 km. • Sedimentation rates can vary from 1 to 1000 m/m.y. (Fig. 32). Rates below and above these values can be important locally, but burial histories between these limits are most common. • Sedimentation rate for a passive margin (e.g. Atlantic margin) changes as it evolves from a rift basin (100-50 m/m.y) to a passive margin basin (20-10 m/m.y.). The lowest sedimentation rates (~ 10m/m.y.) are found in intracratonic basins. • Strike-slip and forearc basins are characterized by much higher rates (1000-100 m/m.y.). • Foreland basins experience the most varied sedimentation rates, but generally fall in the middle. • The highest sedimentation rates are found in areas of rapidly prograding river deltas (e.g. U.S. Gulf Coast basin), where sediment deposition can be much as 1000-5000 m/m.y. • Geothermal gradients, in sedimentary basins, also vary widely, from as low as 10o – 15oC/km to as high as 50o – 60oC/km. Part of this variation can be attributed to differences in the background thermal state of the crust on which the basin rests. However, the thermal properties of sediments (e.g., thermal conductivity) and physical processes acting within basins (e.g., sedimentation and groundwater flow) are also important determinants. 44 Formation of sedimentary basins Sedimentation and Subsidence • A sedimentary basin is any downwarped area of the continental or oceanic crust where sediments accumulate and compact with burial into sedimentary rock. • The accumulation and removal of these rocks define the life cycle of a basin, from the initial event that creates the basin to uplift and destruction. • SA sedimentary basin forms when a topographic low is created in the basement rock through either tectonic subsidence or sedimentation subsidence, or both. • Sedimentation subsidence can be defined as the downward movement of the basement rock- sedimentary rock contact in response to sediment loading (e.g. a major river delta). • Tectonic subsidence is the subsidence of the basement rock that occurs, or would occur, in the absence of sedimentation (e.g. the deep ocean basins). • In general, both tectonic subsidence and sedimentation are necessary for the creation of a sedimentary basin. Sediments accumulate only in topographic lows, thus a basin must generally exist before the fill. On the other hand, sedimentation reinforces the tectonic subsidence that was initiated by a basin-forming event. Isostasy and Flexure • Isostasy is the fundamental principle governing the development and evolution of topography on the earth’s surface. Types of sedimentary basins Rift and Passive Margin Basins • The largest sedimentary basins on earth are the oceanic basins, covering approximately two- thirds of the earth’s surface area. • The formation of these basins is well understood in the light of plate tectonic theory. New oceanic crust is formed by the upwelling of mantle material at mid-oceanic spreading ridges, where the effective lithospheric thickness is essentially zero. As the newly formed lithosphere moves away from the ridge, through the process of seafloor spreading, it cools and thickens, becomes more dense, and subsides through a process of isostatic compensation. • The thermal and structural evolution of oceanic basins result from the initial rift basin to the final passive margin basin. • An initial thermal event leads to cooling, thermal contraction and tectonic subsidence. The tectonic subsidence is then increased by loading from crosional products washed off adjacent continents. In its final stage, an oceanic basin is destroyed through subduction or continental collision. 45 • The formation of rift basin is characterized by two phases of subsidence. During the initial extensional event, relatively low density crustal material (~ 2800 kg/m3) is thinned and replaced by higher density mantle material (~ 3200 km/m3) upwelling from below and isostatic subsidence occurs. The hot mantle material then cools and its density increases through thermal contraction, leading to a second phase of slower tectonic subsidence. • Mekenzie’s model is often applied (and mis-applied) to estimate the timing of hydrocarbon generation. The usual procedure is to “backstrip” sedimentary basin fill for the purpose of separating tectonic subsidence from the total subsidence. This is done by applying the principle of isostasy and compensating for factors such as sediment compaction and changes in sea level. • The estimated tectonic subsidence curve is then compared to Meckenzie’s (1978) theoritical predictions and a “best” value for the stretching factor β is found. Once β is known, heat flow can be estimated, temperature calculated and source rock maturity is predicted (provided that the location of the source rock in the basin fill is known). • This is a straight forward approach, but there are many determinants that must also be taken into consideration if meaningful estimates of the thermal history are to be made. These include the depression of heat flow by sedimentation, the thermal conductivity of rocks within the basin, the surface temperature, and the possible influence of groundwater flow. • The relative importance of these intra-basin factors grows with passing time as the influence of the initial basin-forming event diminishes. Intracratonic Basin • Intracratonic, or platform, basins form on continental interiors. They are typically a few hundred kilometers wide and contain a few kilometers of flat-lying sedimentary rocks recording continuous subsidence and sediment deposition over periods of time greater than 100 m.y. • It has been speculated that the formation of these basins, like rift basins, was controlled by some type of heating or thermal event followed by thermal contraction. • For the formation of intracratonic basins, there are however, several other alternative hypotheses too. These include 1) an increase in density of the crust due to one or more phase transitions, 2) rifting, 3) mechanical subsidenc reactivation alon e caused by an isostatically uncompensated excess mass of igneous intrusions, 4) tectonic g older structures, or 5).some combination of these or other theories. Foreland Basins • Foreland basins are asymmetric, wedge-shaped accumulations of sedimentary rock that form adjacent to fold-thrust belts. • Migration of the fold-thrust sheet loads the lithosphere, causing isostatic subsidence underneath the core of the orogen and flexural down-warping in the adjacent foreland. • The foredeep, that forms next to the orogenic belt, rapidly fills with sediment eroded from the adjacent mountains. Sedimentation amlifies flexural subsidence, and thus a foreland basin is formed. 46 • The foreland basin process continues until the forces driving uplift and orogeny cease. Erosion then dominates, reducing the weight of the mountain chain, leading to uplift and further erosion. The life cycle of a foreland basin is thus one of fairly rapid burial and subsidence followed by a much longer period of uplift and erosion. • Most source rocks buried by the foreland basin fill probably go through a relatively short heating and maturation phase, followed by a longer cooling phase. Other Types of Basins • There are many other types of basins too, such as, strike-slip, forearc and backarc. • Strike-slip or pull apart basins are formed by lateral movement along transform faults, literally pulling the crust apart and creating a void that fills with sediment. • Backarc and forearc basins form in back of and in front of volcanic arcs, respectively, near subduction zones. • Backare basins may form from active seafloor spreading and rifting, in which case they exhibit high heat flow. In other cases, backare bsins are apparently passive features that may merely represent trapped segments of old oceanic crust. • Forearc basins are the result of sediments filling the topographic low created by subduction. STRUCTURAL A D THERMAL EVOLUTIO OF SEDIME TARY BASI S • A question arises whether there is any link between the structural and thermal evolution of a sedimentary basin. As far as petroleum system is concerned, the influence of initial basin- forming thermal events is indirect or limited importance in determining temperature of the basin fill at the time hydrocarbons are generated. • Temperature of the sedimentary fill is, however, more sensitive to intrabasin factors, such as, thermal conductivity, groundwater flow, sedimentation and surface temperature. • Sedimentary basins are never in complete thermal equilibrium and groundwater flow may drastically change the distribution of thermal energy within a basin. • Heat flow is generally a more useful measure of the thermal state of sedimentary basins than temperature gradient alone, because the geothermal varies according to thermal conductivity of different lithologies. Sources of heat • Roughly 40% of surface heat flow, on the continents, comes from a layer of radioactively enriched crystalline rocks about 10 km thick. The remaining 60% heat flow comes from a combination of radioactive sources in the lower crust and upper mantle, as well as a convective flux into the base of the thermal lithosphere. • The half-life of common heat-generating elements (K – U and Th) is of the order of 109 year or greater, thus the radioactive component of heat flow has not change appreciably since the Precambrian. 47 • In contrast, heat flow into the base of the lithosphere can vary markedly, as shown by the passage of the lithosphere over hot spots with resultant isostatic uplift, enhanced heat flow, and volcanism. • Temperature-dependent source rock maturation is, however, relevant to determine the present-day thermal state as a starting point for exploration back to the likely thermal state at the time oil and/or gas were formed. ESTIMATI G TEMPERATURE A D HEAT FLOW I SEDIME TARY BASI S Temperature • Temperature data, usually available for analysis, are bottom-hole temperatures (BHTs) measured during the geophysical logging of oil and gas wells. BHTs represent direct measurements of temperature at depth (1 – 6 km). • Unfortunately, BHTs are noisy and tend to be lower than true formation temperatues due to cooling effect of drilling fluid circulating at the bottom of boreholes. Corrections can be made for drilling disturbance, but the information needed to make accurate corrections is usually not available. Thermal Conductivity • Thermal conductivity of rocks and sediments is a physical property that is determined by mineralogy, porosity and temperature. • Most sedimentary rocks are an aggregate of minerals with pore spaces saturated with saline water. Their bulk thermal conductivity depends on both the solid rock component and the pore fluid. A number of different mixing models have been proposed to relate the thermal conductivity of an aggregate to its individual components. • Over the range of temperatures, found in sedimentary basins, matrix thermal conductivity tends to decrease with increasing temperature. • The in situ thermal conductivity of most sedimentary rocks is in the range of about 1.0 to 4.5 w/mk, although some lithologies fall outside of this range. Most coals can be as low as 0.25 w/mk. In contrast, halite and quartzite are about 5-7 w/mk. Most shales are probably less than 1.5 w/mk, clean sandstones 3-4.5 and carbonates 2-3 w/mk. It is, however, risky to estimate thermal conductivity on the basis of lithology alone. • To overcome the dicullty, efforts have been made to estimate thermal conductivity from geophysical well logs. In many cases, strong correlations have been found between thermal conductivity and one or more log parameters, such as, resistivity, seismic velocity and density. 48 CO TROLS O TEMPERATURE I SEDIME TARY BASI S Heat Flow and Thermal Conductivity • Because the primary mode of heat transport in the crust is conduction, both heat flow and thermal conductivity are equal importance in determining temperature in sedimentary basin fill. • Heat flow is inversely correlated to tectonic age, and is depressed by sedimentation. Heat flow in young (< 25 Ma) rift basins can be as high as 90-120 mw/m2 or higher, but it decreases with increasing age. Foreland basins are associated with post-Precambrian orogenic belts and therefore tend to have heat flows in the range of 50-70 mw/m2. • Intracratonic basins generally have heat flows in the range of 30-50 mw/m2, reflecting their location on old, stable cratons. Other types of basins, such as, pull-apart or backarc basins may have young tectonic ages and can have high heat flows. • Heat flows in basins subject to sedimentation rates higher than 100 m/m.y. (e.g., passive margins) can be extremely depressed. • Any relatively thick stratigraphic section tends to be composed of a variety of different lithologies. Some of these may have thermal conductivities that are relatively high and some relatively low. Some times an average thermal conductivity of a section, containing diverse lithologies, is taken about 2.5 w/mk. Surface Temperature • Surface temperature is an important boundary condition on geothermal conditions. The temperature, at the earth’s surface is determined by climate. Sedimentation • Sedimentation depresses heat flow and the depression persists long after sedimentation ceases (assuming no erosion). The magnitude of depression depends on the thermal conductivity of the sediments deposited and the rate and duration of sedimentation. • The lower the thermal conductivity of the sediments, the greater the reduction in heat flow. Once sedimentation ceases, it may take tens of millions of years or more for the heat flow deficit at the surface to be allevated. Groundwater Flow • Groundwater flow has the potential to be an effective agent for redistributing heat in sedimentary basins. The heat capacity of water (~ 4200 J/kgk) is more than four times as high as the average matrix component of sedimentary rocks (~ 1000 J/kgk). • Vertical fluid movement is usually required to disturb the thermal regime. Little or no heat is transported by the horizontal movement of groundwater, because isotherms are almost always parallel to the ground surface. 49 • The extend to which heat flow (or the geothermal gradient) is enhanced or reduced by upward or down-ward movement of groundwater depends on the Darey (volumetric) velocity and depth of fluid circulation. • Groundwater moves: (1) in response to potential gradients or (2) as a result of free convection. • Common geologic mechanisms for creating potential gradients are sediment compaction and elevation gradients. Regional groundwater flow over distances of 100-1000 km, due to potential gradients arising from elevation differences has been documented for several sedimentary basins. • In foreland basins, the groundwater flow pattern is typical. In the foothills of the mountain range, where water infiltrates at high elevations, the geothermal gradient and surface heat flow are depressed as heat is carried downward by moving groundwater. Near the midpoint of the foreland basin (i.e. axis of the basin fill), flow is largely horizontal and the effect on the basin temperature is minimal. At the distal edge of the basin, flow is forced upward by the basin geometry, leading to a high geothermal gradient and high surface heat flow. • Thermal anomalies, associated with ground water flow, can dramatically influence the temperature-dependent oil and gas generation, and the flow systems themselves may play a role in oil and gas migration. • Free convection in sedimentary basins may passibly arise from density gradients due to thermal expansion or the presence of solutes. For free convection to occur, the permeability of the porous medium must be sufficiently high and a density inversion must exist, with higher density fluids overlying less dense. However, little is known about the occurrence or significance of free convection in sedimentary basins. PROCESSES DIAGE ESIS CATAGE ESIS A D METAGE ESIS OF ORGA IC MATTER Main Features • On burial, organic matter, in sedimentary rock, undergoes numerous compositional changes that are controlled initially by microbes and later mainly by thermal stress. • Thermal maturation is divided into three stages: (1) diagenesis (Ro < 0.5 %), (2), catagenesis (0.5% to 2.0% Ro), and (3), metagenesis (2.0% to 4.0% Ro). • Kerogen, the major global precursor of petroleum, consist of, selectively preserved, resistant biological materials (algal, pollen, spores and leaf cuticle) and the degraded residues of less resistant biological organic matter (amorphous material) in variable proportions. • Kerogen formation is complete by the end of diagenesis. The mode of kerogen formation exerts a strong influence on its structure and bulk composition, and thus on oil and gas generating characteristics, during catagenesis. 50 • Sulfur rich type II kerogen, occuring in carbonate-evaporite source rocks, can generate oil at low levels of thermal stress; while, low sulfur type II kerogen requires more thermal energy to generate oil, and type I and type III kerogens still more. • High-wax oils appear to be generated from both wax ester and biopolymeric precursors, the first of which generates at an early stage of catagenesis and the other throughout catagenesis. • In the latter part of catagenesis, all source rocks contain strongly enhanced proportions of hydrocarbon gases (wet gas). Throughout metagenesis source rock kerogens are strongly depleted in hydrogen and generate dry gas (methane) and sometimes hydrogen sulfide or nitrogen. ASSESSI G ATURAL OIL EXPULSIO FROM SOURCE ROCKS BY LABORATORY PYROLYSIS Introduction • Determining the amount of oil, that may be expelled from a pod of active source rock, is an important consideration in assessing and ranking the hydrocarbon potential of a petroleum system. • Once a source rock has been identified and its mature and overmature volume determined, reliable expulsion efficiencies may be used to determine the ultimate petroleum charge. Al though economic accumulations from this charge will be determined by secondary migration and trapping, the ultimate charge is critical in evaluating the efficiencies of these processes within a petroleum system. • Laboratory pyrolysis methods offer a feasible approach in understanding the primary oil migration and determining expulsion efficiencies of source rocks. • Petroleum formation, as determined by hydrous pyrolysis, consists of two reactions; (1) partial decomposition of kerogen to bitumen, and (2) partial decomposition of bitumen to oil (Lewan, 1985). • The extracted bitumen is a tarry substance that consists of many high melecular weight components. • During maturation of kerogen in source rock, expansion of bitumen, into the rock matrix, takes place during decomposition of kerogen to bitumen (Lewan, 1987). This bitumen impregnates the micropores and bedding plane partings, as a result of a net volume increase in the organic matter within a confining mineral matrix. • Petrographic and petrophysical data suggest that the development of a continuous bitumen network is essential for oil migration within the oil expulsion from effective source rock. • There are three causes of volume increase, during maturation of kerogen. The fist one involves the chemical volume increase that accompanies thermal cracking, as observed in petroleum refining. The second involves the physical volume increase, resulting from thermal exponsion of the generated oil. The thrid involves a physicachemical voluem increase due to the uptake of more dissolved water in the bitumen with increasing maturity (Lewan, 1991). 51 SECO DARY MIGRATIO A D ACCUMULATIO OF HYDROCARBO S • Secondary migration is the process by which petroleum is transported from the pod of active source rock to the trap. Most petroleum migrates as a separate, immiscible phase through water saturated rock. • The driving force for migration is the vertical buoyancy force due to the lower density of petroleum compared to that of formation water. • The capillary pressure difference between the oil and water phases opposes the buoyancy force, discouranging the entry of petroleum into smaller water-wet pores. The interaction of these two forces causes petroleum to migrate along coarser parts of the “carrier bed”. • ‘A trap includes a reservoir and a seal rock that are in a three-dimentional configuration, capable of storing petroleum in the subsurface. • Reservoired petroleums are classified into three types: 1) gas reservoirs, 2) gas condensate reservoirs, and 3) oil reservoirs. • Gas reservoirs contain mostly methane (C1) and some ethane through pentane (C2 – C5). Gas condensate reservoirs are entirely gas phase in the subsurface, but produce a liquid (or condensate) at the surface, that is usually rich in hexane through decane (C6 – C10). Some condensates contain significant quantities of higher molecular weight material in the C30 range. • Oil reservoirs are liquid in the subsurface and remain liquid when produced at the surface (crude oil). Oil is rich in heavier hydrocarbons (C15+). Substantial quantities of gas (rich in C1 – C5 and possibly N2, CO2 and H2s, originally dissolved in the subsurface) are usually produced with oil. • When petroleum reaches a trap, the accumulation process starts. The geochemical composition of this megrating petroleum is constantly changing because the thermal maturity of the source rock is increasing from mature to overmature. • As maturity increases over time, gas-oil ratio increase. Similarly, during the preservation time, processes, such as, biodegradation may affect the hydrocarbons in some parts of a reservoir more than others. Establishing migration direction • A study of the geochemical properties of oils and gases, in accumulations, within a petroleum system can add useful information about the direction from which a field is filled. SEAL • Seal is an important component of a trap. Without effective seals, hydrocarbons will migrate out of the reservoir rock with time and the trap will lack viability. • Most effective seals, for hydrocarbon accumulations, are formed by relatively thick, laterally continuous, ductile rocks with high capillary entry pressures. However, other types of seals may be important parts of individual traps (e.g. fault zone material, volcanic rock, asphalt and permafrost). 52 • All traps require some form of top seal, however, many traps are more complicated and require, in addition to a top seal, other effective seal too. • In case of stratigraphic trap, facies changes from porous and permeable rocks to rocks with higher capillary entry pressures can form lateral seals. Similarly, lateral diagenetic change can result in lateral seal from reservoir to tight rocks. SUBSIDE CE HISTORY • Present-day stratigraphic thicknesses are a product of cummulative compaction through time. A quantitative analysis of subsidence rates, through time, called geohistory analysis, which relies primarly on the decompaction of stratigraphic units to their correct thickness at the time of interest. Introduction to Geohistory Analysis • Geohistory analysis aims at producing a curve for the subsidence and sediment accumulation rates through time. In order to do this, three corrections to the present stratigraphic thicknesses need to be carried out: 1. Decompaction 2. Paleobathymetry 3. Absolute sea level fluctuations • The time-depth history, of any sediment layer, can be evaluated, if the three above mentioned corrections are applied. Such a time-depth history can also be tested from independent mothods too, such as: 1. Organic thermal indicators. 2. Mineralogical thermal indicators. • Organic thermal indicators include: vitrinite reflectance, spore coloration or fluorescence, atomic ratios of kerogens etc; whereas, mineralogical thermal indicators evaluates the abundance of certain index minerals, such as illite versus smectite etc. These thermal maturation indices allow geohistory curves to be calibrated. • The addition of a sediment load to a sedimentary basin causes additional subsidence of the basement. This is simply due to repacement of water or less commonly air, by sediment. The total subsidence is therefore partitioned as follows: 1. tectonic driving force 2. sediment load • The way in which this partitioning operates depends on the isostatic response of the lithosphere. The simplest assumption is that any vertical column of load is compensated 53 locally (Air isostacy). This implies that the lithosphere has no strength to support the load. Alternatively, the lithosphere may transmit stresses and deformations laterally by regional flexture. The same load will threrefore cause a smaller subsidence in the case of lithosphere with a strength sufficient to cause flexure. • The technique whereby the effects of the sediment load are removed from the total subsidence to obtain the tectonic contribution is called back-stripping. Backstripped subsidence curves are specially useful in investigating the basin-forming mechanisms. • Burial history and thermal history can be used to determine the oil and gas potential of a basin and to estimate reservoir porosities. • Burial history curves, form a number of locations, can also be used to construct paleostructure maps at specific time slices. • Combine with information on thermal maturity, this can be a powerful tool in evaluating the timing of oil migration and likely migration pathways in relation to the development of suitable traps. Decompaction • Decompaction technique seek to remove the progressive effects of rock volume changes with time and depth. • Any compaction history is likely to be complex, being affected by lithology, overpressuring, diagenesis and other factors. • Porosity can be estimated from downhole electrical logs, such as, sonic, neutron and desnity logs, which an sensity to lithology and porosity. • To calculate the thickness of a sediment layer at any time in the past, it is necessary to move the layer up the appropriate porosity-depth curve: this equivaluent to sequentially removing overlying sediment layers and allowing the layer of interest to decompaction. In doing so, we keep mass constant and consider the changes in volumes and thus thickness of the sediment layers. • Through mathematical equations, the decompacted thicknesses are calculated. It may be considered that the total volume of a sediment layer is the volume of the sediment grains plus the volume due to pore filling water. On decompaction the sediment volume remains the same, only the volume of water expands. • The new decompacted thickness of the sediment layer is the sum of the thickness due to the sediment grains and the water. • Mathematical equations calculate the thicknesses of a sediment layer at any time from the time of deposition to the present day. A decompacted subsidence curve can thus be ploted. The sources of the data for the plotting the subsidence curve are the stratigraphical boundaries, of presumed known absolute age, defining stratigraphical units of known present day thickness. • All present depths, of stratigraphic units, are, however, in relation to a present day datum, normally taken as present mean sea level. 54 • It is, however, necessary to correct the decompacted subsidence curve for firstly the difference in height between the depositional surface and the regional datum (paleobathymetric correction) and secondly, for past variations in the ambient sea level to the todays sea level (eustatic correction). • Finally, the sediment weight drives basement subsidence. In order to calculate the true tectonic subsidence, it is necessary to remove the effects of the excess weight of the sediment compared to water. Tectonic subsidence Paleobathymetric Corrections • Estimation of water depth, for a given stratigraphic horizon, is not easy, yet it is essential to study burial history accurately. Information on paleobathymetry comes from a number of sources, such as: i. benthonic microfossils, and less commonly ii. sedimentary facies and iii. distinctive geochemical signatures • Most obvious geochemical data relate to the carbonate dissolution depth (CCD) before which calcareous material is dissolved. Some mineral species, such as, glaucony and phosphates may also provide some useful information regarding paleowater depth. Eustatic Corrections • There is evidence of global sea level fluetuations and the controversy surrounding the precise significance of the first, second and other cycles. Bearing in mind the uncertainties, it is, however, advisable to decompact, ignoring any possible global sea level fluctuations. Sediment Load • The true tectonic subsidence is obtained after the removal of the subsidence due to the sediment load and after corrections for variations in water depth and eustatic sea level fluctuations. • ”Worked example on decompaction”. THERMAL HISTORY • Subsidence in sedimentary basins causes material, initially deposited at low temperatures and pressures, to be subjected to higher temperatures and pressures. • Sediments may pass through diagenesis, then metamorphic regimes and may contain indices of their new pressure-temperature conditions. 55 • Thermal indices are generally obtained from either dispersed organic matter or from minerals. • Numerical values of the organic geochemical parameters are dependent on time, thermal energy and type of organic matter. The Arrhenius Equation (Chemical Kinetics) • It is now believed that the effects of depth on the maturation of organic matter are of minor importance, the most important factors being temperature and time. Pressure is relatively unimportant, though pressure is directly related to depth of burial. • The relationship between temperature and the rate of chemical reactions is given by the Arrhenius equation. K = Aexp (-Ea/RT) Where: ‘K’ is the reaction rate ‘A’ is constant, sometimes termed as frequancy factor ‘Ea” is the activation energy ‘R’ is universal gas constant ‘T’ is the absolute timperatue (oK). The constant in the equations can be estimated from compilations of organic metamorphism. The activation energies of each individual reaction, involved in the organic maturation are not known, but for each orgenic matter type a distribution of activation energies may be established from laboratory and field studies. • Arrhenius equation suggests that the reaction rates should increase exponentially with temperature, and a 10 oK rise in temperature (from 50 oC to 60 oC) causes the reaction rate to double. • The rate of increase in reaction rate, however, slows down with increasing temperature, so at 200 oC the reaction rate increases by a factor of 1.4 for a 10 oC rise in temperature. • Time and temperature, both, influence organic maturation, a view supported by the occurrence of shallower oil generation, as the sediments containing the organic matter, become older. Paleotemperatures • We are dealing with the various internal factors that influence the temperatures within sedimentary basins: 1), variations in thermal conductivity, 2), internal heat generation, and 3), convective/advective heat transfer within sediments. 56 Effects of Thermal Conductivity • Basides lithological variations, thermal conductivities of sediments vary as a function of depth because of their porosity loss with burial. Since K (coefficient of thermal conductivity) varies with depth, temperature gradients must also vary with depth in order to maintain a constant heat flow. • It present dayheat flow can be calculated from a borehole by measurement of conductivities and surface and bottom hole temperatures, equations can be used to find the temperature at any depth. If paleoheat flow is assumed to be constant with depth, the temperature history of any selected stratigraphic level can be estimated. • The thermal conductivities can be estimated if the lithology and pore-filling fluid is known. Effects of internal heat generation in sediments • Heat generation by radioactive decay in sediments may significantly affect the heat flow in sedimentary basins (Rybach, 1986). Such heat production, however, varies with lithology, generally lowest in evaporites and carbonates, low to medium in sandstones, higher in shales and siltstones and very high in black shales. • In the continents, crustal radioactivity may account for a large proportion (20-60%) of the surface heat flow. The effect of the internal heat generation is greatest at large depths. Effects of Water Flow • Temperatures, in sedimentary basins, may also be affected by the advective flow of heat through regional aquifers. • Such process may cause anomalously low surface heat flows at regions of recharge and anomalously high surface heat flows in regions of discharge. • Model studies suggest that the temperature distribution is dominated by convection above the Paleozoic, while the heat flows in the Precambrian can be explained simply by conduction. • The most strongly water flow affected basins are likely to be continental basins with marginal uplifts, such as foreland basins and some intracratonic rifts and sags. • I DICATORS OF FORMATIO TEMPERATURE A D THERMAL MATURITY Estimatio of formation temperature from borehole. • Formation temperatures from boreholes are used in thermal modeling studies to calculate the geothermal gradient and basal heat flow to the sedimentary section. 57 Vitrinite reflectance • Vitrintie reflectance is the most widely used indicator of maturity of organic materials. Vitrinite reflectance tends to be unreliable at low level of thermal maturity (Ro less than 0.7 or 0.8%). Other Burial Indices • Besides vitrinite reflectance, other optical parameters on organic material include sporinite microspectrofluorescence and spore, pollen and conodont colouration scales are also utilized. • Mineralogical parameters are controlled by the temperature and chemical properties of the diagenetic environment of the sediment. • Application of Vitrinite Reflectance measurements is given on page 291. • GEOTHERMAL A D PALEOGEOTHERMAL SIG ATURES OF BASI TYPE • Vitrintie reflectance measurements can be used to constrain paleotemperatures and paleogeothermal gradients. Three main types of paleogeothermal history have been suggested. • 1. Basins with normal or near normal paleogeothermal history. • 2. Cooler than normal (hyperthermal) basins • 3. Hotter than normal (hyperthermal) basins. • Old passive margins are considered mature margins with near-normal geothermal gradients. Old passive margins have present day geothermal gradients of 25-30 oC per km. Vitrinite reflectance profiles show Ro about 0.5% at a depth of 3 km, and the shape of the curve is sublinear. • Hypothermal basins include oeanic trench, outer forearc and foreland basins. • Hyperthermal basins are those found in regions of lithospheric extentions such as backarc basins, oceanic and continental rift systems, some strike-slip basins and the internal arcs of zones of B-type subductions. This follows from the mechanics of basin formation in stretched regions. • Oceanic rifts are zones of very high heat flows. Some Californian strike-slip basins have very high geothermal gradients i.e., 200 oC per km of depth, therefore, under such conditions very young sediments can be highly mature. • Continental rifts have high present day heat flows (> 50 oC/km to 100 oC/km) and ancient continental rifts have intense organic maturation in their contained sediments. • Internal are heat flows are elevated because of magmatic activity. Similar patterns are found in ocean-continental collision zones, such as the Andean Cordillera and hyperthermal events may also effect parts of continent-continent collision zones. • The heat flows of the main genetic classes of sedimentary basin are summarized in Fig. 33. 58 Figure 1: Kerogene transformation coefficients (after Waples, 1980) Figure 2: Thermal conductivity of common rocks. 59 Figure 03: Components of hydrocarbon supply and composition assessment. Figure 4: Inert Kerogene. 60 Figure 5: Pyrolysis-gas choromatogram of lacustrine shale (Alkesinac shale, Yugoslavia) Figure 6: Pyrolysis-gas choromatogram of marine shale (Kimmeridge Shale, North Sea) 61 Figure 07: Pyrolysis-gas choromatogram of shale dominated by vitrinitic material (Tertiary, Gulf of Mexico) 62 Figure 08: Pyrolysis-gas choromatogram of degraded marine organic matter (Cretaceous, DSDP site 534). Figure 09: Pyrolysis-gas choromatogram from a sample dominated by inert kerogen. 63 Figure 10: Classification of the three main types of kerogen in a HI vs OI diagram. 64 Figure 11: HI T max diagram. Figure 12 effect of weathering on various geochemical indices. 65 Figure 13: Changes in vitrinite reflectance with increasing thermal maturity. Figure 14: Normal vitrinite reflectance profile from china sea. 66 Figure 15: effect of different kinetics on hydrocarbon generation (from Tissot et al. 1987). Figure 16: Petroleum components. 67 Figure 17: Gross composition of normal producible crude (from Tissot and Welte 1984) Figure 18: Oil Classification scheme based on bulk geochemical character (after Tissot and Welte, 1984). 68 Figure 19: hydrocarbons observed in modern algae (After Gelpi et al., 1970). Figure 20: Effects of biodgradation on the saturated fraction of a suite of crude oil from the Niger Delta. 69 Figure 21: Summary of effects of biodegradation on chemical and physical properties of crude oils (from Clayton, 1990) 70 Figure 22: Schematic representation of the development of sour (high sulfur) crude oils. Figure 23 A: Precursors for the major biomarker classes (Waples. 1985) 71 Figure 23 B: names and various ways of depicting n-alkanes (from Waples, 1985). Figure 24: relationship between precursor and n-parafin distribution (from Lijmback, 1975). 72 Figure 25: An example of the use of methane carbon isotopic composition to determine probable source. Figure 26. Oil and Gas Fields in the Fictitious Deer-Boar (.) Petroleum system, or the Accumulation related to One Pod of Active Source Rock. 73 Figure 27: Burial history chart showing the critical moment (250 MA) and the time of oil generation (260-240 Ma)for the fictitious petroleum system. This information is used on the events chart (Figure 30). Neogene (N) includes the Quarternary here. All rock unit names used here fictitious. Location used for burial history chart is shown on figures 28 and 29. (Time scale from Palmer 1983.). Figure 28: Plan map showing the geographic extent of the fictitious petroleum system at the critical moment (250 Ma). Thermally immature source rock is outside the oil window. The pod of active source rock lies within the oil and gas windows. 74 Figure 29: geological cross section showing the stratigraphic extent of the fictitious Deer-Boar (.) petroleum system at the critical moment (250 Ma). Thermally immature source roack lies updip of the oil window. The pod of active source rock is downdip of the oil window. Figure 30: the events chart showing the relationship between the essential elements and processes as well as the preservation time and critical moment for the fictitious petroleum system. Neogene (N) includes the Quaternary here. (Time scale from Palmer, 1983.) 75 Figure 31: Geochamical log of a well, showing immature and mature source rocks in the Upper and Lower Cretaceous. Mud gas data were unavailable for this well. 76 Figure 32: Representative tectonic subsidence histories for basins from different tectonic settings. The top graph shows the slops of a range of sedimentation rates after compaction and is provided for reference (After Angevine et al., 1990.) 77 Figure 33: Summary of the typical heat flows associated with sedimentary basins of various types. 78 REFERE CES Abbot, G. D., Lewis, C. A. and Maxwell, J. R., 1985. The kinetics of specific organic reactions in the zone of catagenesis. 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Time and temperature in petroleum formation: application of Lopatin’s method to petroleum exploration. American Association of Petroleum Geologists Bulletin, 64: 916-926. Waples, D. W., 1985. Wood, D. A., 1988. Relationship between maturity indices calculated using Arrhenius equation and Lopatin method implications for petroleum exploration. American Association of Petroleum Geologists Bulletin, 72: 115-134. 80 Zhang Youcheng, Yao Meng and Hao Shisheng, 1991. An application of optimization method – a new calculation method of hydrocarbon generation kinetic parameters. Journal of Southeast Aasian Earth Sciences, 5: 75-80.
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