Peters and cassa sition and thermal maturity from microscopy can be Desmocollinite used to estimate the atomic H/C ratio of a kerogen oco oxided Vitrinit (Figure 5. 2). If the measured atomic H/C differs by more than 0. 1 from the estimated value, both analyses are 如 a H/c results are commonly supported by Tmax and I 0204060.81.012141.61.202.2 data obtained from each whole rock sample using Rock- REFLECTANCE Eval pyrolysis and TOC Coal Figure 5. 3. A complete reflectogram showing the reflectance of all macerals in a kerogen sample. In cases Coal is a rock containing more than 50% organic here selection of the"true"vitrinite population(telocollil matter by weight both coals and sedimentary rocks can ite)is difficult, the trend of Ro versus depth established by contain any combination of macerals. Various classifica many samples is useful for selecting the correct popula ion Here, telocollinite( hatchured) has a mean %Ro of tions of these organic-rich rocks are found in the litera- 61. This sample contains significant amounts of oxidized ture(e.g, Cook and Sherwood, 1991). Not all coals are vitrinite and semi-fusinite that could be mistaken for composed of humic organic matter (higher plant, type Ill vitrinite. Courtesy of S C. Terman.) kerogen). Humic and sapropelic coals contain less than 10 and more than 10% liptinite, respectively. Humic coal has long been recognized as a source for gas, primarily orography alone is too imprecise to evaluate the methane and carbon dioxide. However, boghead and troleum potential of a source rock, primarily because cannel coals are dominated by type I and II kerogens hydrogen-rich and hydrogen-poor kerogen is difficult to respectively, are oil prone, and thus show high distinguish. Amorphous"kerogen is commonly potential presumed to be hydrogen rich and oil prone, but not all Coals can generate oil, as exemplified by major accu- amorphous kerogens can generate oil. UItraviolet- mulations in Indonesia and Australia. Two principal induced fluorescence microscopy of samples of lor limitations for coals as effective source rocks are(1) thermal maturity distinguishes hydrogen-rich, oil-prone expulsion efficiency and (2)organic matter type (s amorphous(fluorescent)from hydrogen-poor, non- cient hydrogen). Because of the physical properties of generative amorphous (nonfluorescent) kerogen, thick coal seams, generated liquid products are usuall suggesting that petrographic methods might be further adsorbed and generally escape only when cracked to gas and condensate(Snowdon, 1991; Teerman and hwang l,1987) 1991). Coals that can generate and release oil must Organic Facies contain at least 15-20% by volume of liptinite macerals prior to catagenesis, corresponding to an HI of at least Various workers have used the term organic facies as a 200 mg HC/g TOC and an atomic H/C ratio of 0.9 synonym for kerogen facies(based on chemical data)or (Hunt, 1991) palynofacies or maceral assemblage facies(based on etrographic data). Jones(1984, 1987) propose a concise Kerogen and Bitumen Composition definition Detailed structural information on kerogen is limited stratigraphic unit, distinguished ecause of its heterogeneous composition and difficulties on the basis of the character of its organic constituents, without associated with the chemical analysis of solid organic regard to the inorganic aspects of the sediment. matter. Kerogen has been described as a geopolymer, which has been"polymerized"from a random mixture Jones(1984, 1987)has defined organic facies using a of monomers. These monomers are derived from the combination of three types of kerogen analyses: atomic diagenetic decomposition of biopolymers, including mitted-reflected light microscopy. He showed that all 1984). This view has led to many publications showing organic facies can exist in either carbonates or shales and generalized chemical structures for kerogen, none of that there is little evidence that TOC requirements are which are particularly informative ower for carbonate than for shale source rocks. Integra The discovery of insoluble biopolymers in living tion of organic facies studies with the concepts of ence stratigraphy is a step toward improving our a reappraisal of the structure of kerogen(Rullkotter and lity to predict the occurrence of a source rock (e.g Michaelis, 1990). In the modified scheme, more emphasis When used together, elemental analysis, Rock-Eval is placed on selective preservation of biopolymers and less on reconstitution of omers, Progress has been pyrolysis and Toc, and organic petrography are achieved by the application of specific chemical degrada- owerful tools for describing the richness, type, and tion ke et ter and Se thermal maturity of organic matter. Jones and Edison 1985), and spectroscopic techniques (Mann et al., 1991) (1978)and Jones(1984)have shown how maceral compo- Structural elucidation techniques are beyond the scope of
98 Peters and Cassa Desmocollinite Telocoliinite Oxidized Vitrinite Semi-Fusinite N = 100 %R0= 0.61 (Tdocollinite) Liptinites ft Fusinite 0.4 0.6 0.8 1.0 1.2 1.4 % REFLECTANCE 1.8 2.0 2.2 Figure 5.3. A complete reflectogram showing the reflectance of all macerals in a kerogen sample. In cases where selection of the "true" vitrinite population (telocoliinite) is difficult, the trend of Ro versus depth established by many samples is useful for selecting the correct population. Here, telecollinite (hatchured) has a mean % R0 of 0.61. This sample contains significant amounts of oxidized vitrinite and semi-fusinite that could be mistaken for vitrinite. (Courtesy of S. C. Teerman.) Petrography alone is too imprecise to evaluate the petroleum potential of a source rock, primarily because hydrogen-rich and hydrogen-poor kerogen is difficult to distinguish. "Amorphous" kerogen is commonly presumed to be hydrogen rich and oil prone, but not all amorphous kerogens can generate oil. Ultravioletinduced fluorescence microscopy of samples of low thermal maturity distinguishes hydrogen-rich, oil-prone amorphous (fluorescent) from hydrogen-poor, nongenerative amorphous (nonfluorescent) kerogen, suggesting that petrographic methods might be further refined to better predict generative potential (Senftle et al., 1987). Organic Fades Various workers have used the term organic fades as a synonym for kerogen fades (based on chemical data) or palynofacies or maceral assemblage facies (based on petrographic data). Jones (1984,1987) propose a condse definition: An organic facies is a mappable subdivision of a designated stratigraphic unit, distinguished from the adjacent subdivisions on the basis of the character of its organic constituents, without regard to the inorganic aspects of the sediment. Jones (1984, 1987) has defined organic fades using a combination of three types of kerogen analyses: atomic H/C ratios, Rock-Eval pyrolysis and TOC, and transmitted-reflected light microscopy. He showed that all organic facies can exist in either carbonates or shales and that there is little evidence that TOC requirements are lower for carbonate than for shale source rocks. Integration of organic facies studies with the concepts of sequence stratigraphy is a step toward improving our ability to predict the occurrence of a source rock (e.g., Pasleyetal.,1991). When used together, elemental analysis, Rock-Eval pyrolysis and TOC, and organic petrography are powerful tools for describing the richness, type, and thermal maturity of organic matter. Jones and Edison (1978) and Jones (1984) have shown how maceral composition and thermal maturity from microscopy can be used to estimate the atomic H/C ratio of a kerogen (Figure 5.2). If the measured atomic H/C differs by more than 0.1 from the estimated value, both analyses are suspect and are repeated. These maturity and atomic H/C results are commonly supported by Tmax and HI data obtained from each whole rock sample using RockEval pyrolysis and TOC. Coal Coal is a rock containing more than 50% organic matter by weight. Both coals and sedimentary rocks can contain any combination of macerals. Various classifications of these organic-rich rocks are found in the literature (e.g., Cook and Sherwood, 1991). Not all coals are composed of humic organic matter (higher plant, type IB" kerogen). Humic and sapropelic coals contain less than 10% and more than 10% liprinite, respectively. Humic coal has long been recognized as a source for gas, primarily methane and carbon dioxide. However, boghead and cannel coals are dominated by type I and II kerogens, respectively, are oil prone, and thus show high oil potential. Coals can generate oil, as exemplified by major accumulations in Indonesia and Australia. Two principal limitations for coals as effective source rocks are (1) expulsion efficiency and (2) organic matter type (sufficient hydrogen). Because of the physical properties of thick coal seams, generated liquid products are usually adsorbed and generally escape only when cracked to gas and condensate (Snowdon, 1991; Teerman and Hwang, 1991). Coals that can generate and release oil must contain at least 15-20% by volume of liptinite macerals prior to catagenesis, corresponding to an HI of at least 200 mg HC/g TOC and an atomic H/C ratio of 0.9 (Hunt, 1991). Kerogen and Bitumen Composition Detailed structural information on kerogen is limited because of its heterogeneous composition and difficulties associated with the chemical analysis of solid organic matter. Kerogen has been described as a geopolymer, which has been "polymerized" from a random mixture of monomers. These monomers are derived from the diagenetic decomposition of biopolymers, including proteins and polysaccharides (e.g., Tissot and Welte, 1984). This view has led to many publications showing generalized chemical structures for kerogen, none of which are particularly informative. The discovery of insoluble biopolymers in living organisms, sediments, and sedimentary rocks has led to a reappraisal of the structure of kerogen (Rullkotter and Michaelis, 1990). In the modified scheme, more emphasis is placed on selective preservation of biopolymers and less on reconstitution of monomers. Progress has been achieved by the application of specific chemical degradation (Mycke et al, 1987), pyrolysis (Larter and Senftle, 1985), and spectroscopic techniques (Mann et al., 1991). Structural elucidation techniques are beyond the scope of
5. Applied Source Rock Geochemistry 99 this chapter, although the reader should be aware that asphaltenes, followed by biomarker analysis of the these studies are likely to impact our understanding of generated bitumen (e. g, Cassani and Eglinton, 1986) Biomarker and other correlation technologies, such as Asphaltenes in bitumen are lower molecular weight stable carbon isotope analysis and pyrolysis-gas chro- fragments of kerogen and may be intermediates between matography, are among the most powerful tools for kerogen and bitumen. For example, although mapping petroleum systems to reduce exploration risk, asphaltenes are soluble in polar solvents, they show particularly when oils migrate large distances from their elemental compositions similar to associated kerogens pod of active source rock or when more than one source (Orr, 1986)and similar distributions of hydrocarbon ock pod exists in the basin fill. Based on these finger (Bandurski, 1982; Pelet et al., 1985), including steranes printing techniques, the level of certainty for a petroleum and triterpanes( Cassani and Eglinton, 1986) system is determined. This level of certainty indicates the Lipids can be incorporated into kerogen during diage- confidence that the petroleum from a particular accumu- bitumen and are known as molecular fossils, biological markers,or biomarkers. Biological markers are complex organic compounds composed of carbon, hydrogen, and SCREENING METHODS other elements which show little or no change in structure from their parent organic molecules in living Sedimentary basin analysis(Magoon and Dow organisms(Peters and Moldowan, 1993) geologic and geophysical reconnaissance. Early evalua- Expelled Products presence of thick sedimentary sequences, regional hydro- Petroleum expelled from an active source rock carbon seals, and appropriate reservoir lithologies. Maps primarymigration)(Lewan, Chapter 11, this volume)can using well control, outcrop, and geophysical data must migrate along a fault plane or permeable carrier bed be prepared or revised (secondary migration)(England, Chapter 12, this volume Geochemical screening analyses are practical explo- to a porous reservoir rock (Morse, Chapter 6; Jordan and aton tools for rapid and inexpensive evaluation of large ilson,Chapter 7, this volume)capped or surrounded numbers of rock samples from outcrops and wells by a comparatively impermeable seal ( downey, Chapter Outcrop samples from measured stratigraphic sections 8, this volume)that together form a trap(Biddle and are better than random outcrop samples because they Wielchowsky, Chapter 13, this volume). Examples of can easily be made into a geochemical log that can be how this hap volume. Factors controlling the quantities of petroleum samples from wells include drill cuttings, sidewall cores, needed to saturate the pore space in a source rock prior and conventional cores, in order of decreasing to expulsion an d the efficiency of expulsion are poorly Large numbers of analyses of these rock understood and represent active research topics (e. g. samples are used to make geochemical logs to evaluate Wilhelms et al., 1990; Mackenzie and Quigley, 1988) the thickness, distribution, richness, type, and thermal maturity of source rocks in the basin fill. Evaluating the Accurate estimates of these quantities will improve mass source rock in the basin fill is an important part of sedi- balance calculations Shous of petroleum are proof of a petroleum system mentary basin analysis. The next step is to identify the pod of active source rock, which is the first step in evalu ration clues, particularly when they can be quantified ating a petroleum system. bleed oil an n during removal from the well are called numbers of rock samples fronng method for large and regionally mapped. Cuttings or cores that bubble or The most effective screen wells and outcrops combines Rock-Eval pyrolysis and TOC measurements. live"shows, in contrast to the asphaltic staining of These data are usually supplemented by vitrinite their fluorescence under ultraviolet light, by the color of reflectance and spore coloration results to construct organic solvent extracts, or by the geochemical screening detailed geochemical logs(see Figures 5.4-5.11) methods described later. Quantitative bitumen or hydro- Chapter Appendix B describes key criteria for usef carbon yields from reservoir rocks assist in distin geochemical logs. These include proper(1) sample guishing between commercial and noncommercial spacing, (2) sample quality and storage, and (3) sample subsurface petroleum occurrences(Swanson, 1981) preparate Oils inherit biomarker distributions similar to those in the bitumen from the source rock, thus allowing oil-oil Rock-Eval Pyrolysis and Total organic and oil-source correlation or"fingerprinting"and paleo- Carbon reconstruction of source rock depositional conditions biomarkers is their resistance to biodegradation by Total organic carbon (TOC, wt %)describes the (Peters and Moldowan, 1993). An advantage of uantity of organic carbon in a rock sample and includes aerobic bacteria in the reservoir For heavily biodegraded both kerogen and bitumen. TOC can be determined in oils where biomarkers have been partially altered, corre- several ways, and geologists should be familiar with the lation sometimes requires sealed tube pyrolysis of advantages and disadvantages of each(Chapter
5. Applied Source Rock Geochemistry 99 this chapter, although the reader should be aware that these studies are likely to impact our understanding of kerogen. Asphaltenes in bitumen are lower molecular weight fragments of kerogen and may be intermediates between kerogen and bitumen. For example, although asphaltenes are soluble in polar solvents, they show elemental compositions similar to associated kerogens (Orr, 1986) and similar distributions of hydrocarbons (Bandurski, 1982; Pelet et al., 1985), including steranes and triterpanes (Cassani and Eglinton, 1986). Lipids can be incorporated into kerogen during diagenesis, but many survive as free constituents in the bitumen and are known as molecular fossils, biological markers, or biomarkers. Biological markers are complex organic compounds composed of carbon, hydrogen, and other elements which show little or no change in structure from their parent organic molecules in living organisms (Peters and Moldowan, 1993). Expelled Products Petroleum expelled from an active source rock, (primary migration) (Lewan, Chapter 11, this volume) can migrate along a fault plane or permeable carrier bed (secondary migration) (England, Chapter 12, this volume) to a porous reservoir rock (Morse, Chapter 6; Jordan and Wilson, Chapter 7, this volume) capped or surrounded by a comparatively impermeable seal (Downey, Chapter 8, this volume) that together form a trap (Biddle and Wielchowsky, Chapter 13, this volume). Examples of how this happens are described in the case studies in this volume. Factors controlling the quantities of petroleum needed to saturate the pore space in a source rock prior to expulsion and the efficiency of expulsion are poorly understood and represent active research topics (e.g., Wilhelms et al., 1990; Mackenzie and Quigley, 1988). Accurate estimates of these quantities will improve mass balance calculations. Shows of petroleum are proof of a petroleum system and when encountered during drilling are useful exploration clues, particularly when they can be quantified and regionally mapped. Cuttings or cores that bubble or bleed oil and gas during removal from the well are called "live" shows, in contrast to the asphaltic staining of "dead" shows. The quality of shows can be evaluated by their fluorescence under ultraviolet light, by the color of organic solvent extracts, or by the geochemical screening methods described later. Quantitative bitumen or hydrocarbon yields from reservoir rocks assist in distinguishing between commercial and noncommercial subsurface petroleum occurrences (Swanson, 1981). Oils inherit biomarker distributions similar to those in the bitumen from the source rock, thus allowing oil-oil and oil-source correlation or "fingerprinting" and paleoreconstruction of source rock depositional conditions (Peters and Moldowan, 1993). An advantage of biomarkers is their resistance to biodegradation by aerobic bacteria in the reservoir. For heavily biodegraded oils where biomarkers have been partially altered, correlation sometimes requires sealed tube pyrolysis of asphaltenes, followed by biomarker analysis of the generated bitumen (e.g., Cassani and Eglinton, 1986). Biomarker and other correlation technologies, such as stable carbon isotope analysis and pyrolysis-gas chromatography, are among the most powerful tools for mapping petroleum systems to reduce exploration risk, particularly when oils migrate large distances from their pod of active source rock or when more than one source rock pod exists in the basin fill. Based on these fingerprinting techniques, the level of certainty for a petroleum system is determined. This level of certainty indicates the confidence that the petroleum from a particular accumulation came from a specific pod of active source rock. SCREENING METHODS Sedimentary basin analysis (Magoon and Dow, Chapter 1, this volume) of frontier areas begins with geologic and geophysical reconnaissance. Early evaluations focus on sample and data collection to assess the presence of thick sedimentary sequences, regional hydrocarbon seals, and appropriate reservoir lithologies. Maps using well control, outcrop, and geophysical data must be prepared or revised. Geochemical screening analyses are practical exploration tools for rapid and inexpensive evaluation of large numbers of rock samples from outcrops and wells. Outcrop samples from measured stratigraphic sections are better than random outcrop samples because they can easily be made into a geochemical log that can be compared to nearby geochemical logs of wells. Rock samples from wells include drill cuttings, sidewall cores, and conventional cores, in order of decreasing abundance. Large numbers of analyses of these rock samples are used to make geochemical logs to evaluate the thickness, distribution, richness, type, and thermal maturity of source rocks in the basin fill. Evaluating the source rock in the basin fill is an important part of sedimentary basin analysis. The next step is to identify the pod of active source rock, which is the first step in evaluating a petroleum system. The most effective screening method for large numbers of rock samples from wells and outcrops combines Rock-Eval pyrolysis and TOC measurements. These data are usually supplemented by vitrinite reflectance and spore coloration results to construct detailed geochemical logs (see Figures 5.4-5.11). Chapter Appendix B describes key criteria for useful geochemical logs. These include proper (1) sample spacing, (2) sample quality and storage, and (3) sample preparation. Rock-Eval Pyrolysis and Total Organic Carbon Total organic carbon (TOC, wt. %) describes the quantity of organic carbon in a rock sample and includes both kerogen and bitumen. TOC can be determined in several ways, and geologists should be familiar with the advantages and disadvantages of each (Chapter
Peters and Cassa Appendix C). TOC is not a clear indicator of petroleum cuttings are given in Schaefer et al. (1978), Reitsema et al. otential. For example, graphite is essentially 100%o (1981), and Whelan(1984). Other procedures are used for carbon, but it will not generate petroleum. Some Tertiary sampling gases under pressure(Gas Processors Associa- deltaic marine shales contain up to 5 wt. TOC but tion, 1986). The more advanced aspects of gas geochem- generate little if any petroleum because the organic istry are beyond the scope of this chapter, which deals matter is gas prone or inert. The theory and pitfalls of primarily with rapid screening methods for evaluating Rock-Eval pyrolysis interpretation are discussed by oils and source rocks. However, readers should be aware Peters( 1986)and are not repeated here. Key parameters that analysis of gases is likely to become increasingly are defined in Chapter Appendix D important as future exploration shifts from oil to gas Gas analysis Organic Petrography Residual gas( CrCs) and heavier hydrocarbons in drill cuttings and mud arriving at the shaker table can be Thermal Alteration Index liberated with a blender and analyzed by gas chromat Thermal alteration index (tai) is a numerical scal raphy(GC)at the well site as part of a process called ased on thermally induced color changes in spores and hydrocarbon mud logging. Some systems use a simple hot ollen. Strew-mount slides of kerogen are examined and ethane-plus hydrocarbons. Hydrocarbon mud log ison microscope. The analyst matches the color of the gas curves are commonly available from wildcat wells specimen under one ocular with that of a standard under and provide useful information on hydrocarbon shows the other ocular of the microscope. Several TAI scales (e-g, see Figure 5.7) have been published (e.g, Staplin, 1969; Jones and Alternately, gaseous hydrocarbons can be detected at Edison, 1978). An advantage of TAI is that the greatest the well site or in the laboratory using an oil show color changes occur in the oil window. TAI measure- ments are imprecise because description of color is GC(Schaefer, et al., 1978). In GC, an inert carrier gas subjective, palynomorph thickness and type affect (mobile phase)passes through a column coated with a results, and many samples contain few palynomorphs nonvolatile,high molecular weight liquid(stationary Quantitative spore s)of more r ions. TAI commonly easurements(MarshalL, 1991) recise assessment of raised using a te mperature-pro thermal maturity. Despite limit Petroleum components are separated depending on their provides useful data, even when other maturity param volatility and affinity for the mobile versus stationary ters fail phases as they pass through the column. a plot of Vitrinite reflectance representing single or multiple components and is called Vitrinite refectance(Ro)increases during thermal matu ration due to complex, irreversible aromatization used as a screenin reactions, Approximate Ror TAL, and t tool because it assists in quantitative show detection been assigned for the beginning and end of oil genera (Tissot and Welte, 1984). For this method, cuttings are tion(Table 5.3). Ro versus depth plots generally show and /or heating releases some of the hydrocarbons from how these plots can be used to support the existence of the cuttings into the headspace over the water, which car faults, intrusions, and changes in geothermal gradient be sampled through a septum with a syringe and and how to estimate the thickness of a section lost at an analyzed by GC(e.g, Bernard, 1978; Whelan, 1984) unconformity. This information provides valuable cali Many choose not to use this technique because it is costly bration for reconstructing burial histories nd time consuming and metal cans rust or leak in For vitrinite reflectance, kerogen isolated from sedi storage Furthermore, this method is not particularly mentary rocks is embedded in epoxy on a slide or in an useful for establishing maturity profiles because gas epoxy plug and polished to a flat, shiny surface(Bostick readily migrates. Vitrinite reflectance and Rock-Eval and Alpern, 1977; Baskin, 1979). Measurements are made pyrolysis are more reliable methods for establishing of the percentage of incident light (usually at a wave- rmal maturity profiles than gas analysis ngth of 546 nm) reflected from vitrinite particles Light hydrocarbon gas distributions combined with (preferably telocollinite)under oil immersion(Stach et isotopic compositions can be used to describe the origi 1, 1982). The subscript"o"in Ro refers to oil immersion and level of thermal maturity of the gas (e.g, Rice and ome old papers refer to Ra and Rw, reflectance in Claypool, 1981; James, 1983; Schoell, 1984). Reliable and water, respectively. Vitrinite becomes anisotropic at sampling methods are important because sample high levels of maturity (above about 1%Ro), resulting in handling can alter these gas compositions. For example, the terms Rmin and rmax f the drill cuttings used for headspace gas analyses should be maximum reflectance values obtained upon rotation of pt in gas-tight containers at deep freeze temperatures each particle. Most kerogen studies report random mean to avoid evaporative loss of components. Examples of Ro rather than Rmin or rmax because rotation of the procedures for sampling gases in drilling muds and microscope stage is not requ
100 Peters and Cassa Appendix C). TOC is not a clear indicator of petroleum potential. For example, graphite is essentially 100% carbon, but it will not generate petroleum. Some Tertiary deltaic marine shales contain up to 5 wt. % TOC but generate little if any petroleum because the organic matter is gas prone or inert. The theory and pitfalls of Rock-Eval pyrolysis interpretation are discussed by Peters (1986) and are not repeated here. Key parameters are defined in Chapter Appendix D. Gas Analysis Residual gas (Q-C5) and heavier hydrocarbons in drill cuttings and mud arriving at the shaker table can be liberated with a blender and analyzed by gas chromatography (GC) at the well site as part of a process called hydrocarbon mud logging. Some systems use a simple hot wire detector to make only two measurements, methane and ethane-plus hydrocarbons. Hydrocarbon mud log gas curves are commonly available from wildcat wells and provide useful information on hydrocarbon shows (e.g., see Figure 5.7). Alternately, gaseous hydrocarbons can be detected at the well site or in the laboratory using an oil show analyzer (Espitalie et al., 1984) or by hydrogen stripping GC (Schaefer, et al., 1978). In GC, an inert carrier gas (mobile phase) passes through a column coated with a nonvolatile, high molecular weight liquid (stationary phase). The temperature of the column is gradually raised using a temperature-programmed oven. Petroleum components are separated depending on their volatility and affinity for the mobile versus stationary phases as they pass through the column. A plot of detector response versus time shows separated peaks representing single or multiple components and is called a chromatogram. Headspacegas analysis is sometimes used as a screening tool because it assists in quantitative show detection (Tissot and Welte, 1984). For this method, cuttings are frozen or canned with water and a bactericide. Agitation and/or heating releases some of the hydrocarbons from the cuttings into the headspace over the water, which can be sampled through a septum with a syringe and analyzed by GC (e.g., Bernard, 1978; Whelan, 1984). Many choose not to use this technique because it is costly and time consuming and metal cans rust or leak in storage. Furthermore, this method is not particularly useful for establishing maturity profiles because gas readily migrates. Vitrinite reflectance and Rock-Eval pyrolysis are more reliable methods for establishing thermal maturity profiles than gas analysis. Light hydrocarbon gas distributions combined with isotopic compositions can be used to describe the origin and level of thermal maturity of the gas (e.g., Rice and Claypool, 1981; James, 1983; Schoell, 1984). Reliable sampling methods are important because sample handling can alter these gas compositions. For example, drill cuttings used for headspace gas analyses should be kept in gas-tight containers at deep freeze temperatures to avoid evaporative loss of components. Examples of procedures for sampling gases in drilling muds and cuttings are given in Schaefer et al. (1978), Reitsema et al. (1981), and Whelan (1984). Other procedures are used for sampling gases under pressure (Gas Processors Association, 1986). The more advanced aspects of gas geochemistry are beyond the scope of this chapter, which deals primarily with rapid screening methods for evaluating oils and source rocks. However, readers should be aware that analysis of gases is likely to become increasingly important as future exploration shifts from oil to gas. Organic Petrography Thermal Alteration Index Thermal alteration index (TAI) is a numerical scale based on thermally induced color changes in spores and pollen. Strew-mount slides of kerogen are examined in transmitted light, typically using a split-stage comparison microscope. The analyst matches the color of the specimen under one ocular with that of a standard under the other ocular of the microscope. Several TAI scales have been published (e.g., Staplin, 1969; Jones and Edison, 1978). An advantage of TAI is tfiat the greatest color changes occur in the oil window. TAI measurements are imprecise because description of color is subjective, palynomorph thickness and type affect results, and many samples contain few palynomorphs. Quantitative spore color measurements (Marshall, 1991) offer the possibility of more precise assessment of thermal maturity. Despite limitations, TAI commonly provides useful data, even when other maturity parameters fail. Vitrinite Reflectance Vitrinite reflectance (RQ) increases during thermal maturation due to complex, irreversible aromatization reactions. Approximate RQ, TAI, and Tmax values have been assigned for the beginning and end of oil generation (Table 5.3). RQ versus depth plots generally show linear trends on semi-log paper. Dow (1977b) showed how these plots can be used to support the existence of faults, intrusions, and changes in geothermal gradient and how to estimate the thickness of a section lost at an unconformity. This information provides valuable calibration for reconstructing burial histories. For vitrinite reflectance, kerogen isolated from sedimentary rocks is embedded in epoxy on a slide or in an epoxy plug and polished to a flat, shiny surface (Bostick and Alpern, 1977; Baskin, 1979). Measurements are made of the percentage of incident light (usually at a wavelength of 546 nm) reflected from vitrinite particles (preferably telocollinite) under oil immersion (Stach et al., 1982). The subscript "o" in RQ refers to oil immersion. Some old papers refer to Ra and Rw, reflectance in air and water, respectively. Vitrinite becomes anisotropic at high levels of maturity (above about 1% R<,), resulting in the terms Rmin and Rmax for the minimum and maximum reflectance values obtained upon rotation of each particle. Most kerogen studies report random mean Ro rather than Rmjn or Rmax because rotation of the microscope stage is not required
5. Applied Source Rock Geochemistry Several factors based on the experience of the analyst Reflectograms are we Reflectograms(Figure 5.3)are frequency plots of the Ro trends established above and below the sample can be reflectance of all macerals measured in the polished used to eliminate certain populations of macerals fro consideration. Because TAI and Ro are related ( ones and provide an idea of the difficulty in selecting vitrinite the Ro of the vitrinite population. This process is not particles for measurement may be difficult when there is always reliable, however, because TAI is commonly no clearly predominant population of telocollinite measured on less than a dozen palynomorphs and these ( Figure 5. 3). Ro must be determined using vitrinite might represent recycled organic matter or contamina- because other macerals mature at different rates (e. g tion from drilling mud Dow, 1977b). However, Ro can be extrapolated from Reliability of Ro measurements from single samples reflectance measurements of some macerals other tha increases when by independent maturity telocollinite, such as exinite(Alpern, 1970) parameters (e.g, TAI and Tmax) and Ro versus depth trends established by multiple samples in a well. For the thermally mature stage. In situ vitrinite in some INTERPRETTVE TECHNIQUES samples can be overwhelmed by recycled (high maturity)or caved (ow maturity) particles, Selection of Source Potential Index these particles as the"true"vitrinite might result in During the source rock assessment phase of sedimen- anomalous values compared to the Ro trend established tary basin evaluation, geologists commonly rely on the samples from other depths. As an extreme example, quantity, type, and thermal maturity of organic matter as some Alaskan wells show little change or even a decrease in Ro with increasing depth at shallow well petroleum charge. However, source rock volumetrics depth due to shedding of recycled (high Ro)organic (thickness and lateral extent) must not be ignored.An matter from Mesozoic highlands into thermally "cool oil-prone source rock dominated by type I or II kerogen and showing excellent genetic potential(e.g, 1+ S2>10 Ro cannot be measured in rocks that lack vitrinite mg HC/g rock) may be too thin to charge economically Vitrinite is derived from land plants and is not common significant oil accumulations Source potential index(SPD) in rocks older than devonian because abundant land (Demaison and Huizinga, 1991)is defined as the plants had not yet evolved Reflectance can be measured quantity of hydrocarbons (metric tons) that can be on graptolites in lower Paleozoic rocks(Link et al., 1990). generated in a column of source rock under one square Some oil-prone source rocks that formed on broad meter of surface area(Demaison and Huizinga, Chapter marine carbonate shelves(e. g, Jurassic of Saudi Arabia) 4, this volume). SPI (or"cumulative hydrocarbon or in large lakes(e.g, Lower Cretaceous of West Africa) potential, "according to Tissot et al., 1980)is a simple contain only small amounts of vitrinite due to limited method for ranking source rock productivity because it terrigenous organic matter input. The reflectance of solid integrates both source rock richness and thickness. A bitumen has been calibrated to Ro and is particularly relative source rock ranking system has been developed useful in vitrinite- poor carbonate rocks (Jacob, 1989). by compiling the average SPI values for source rock units Evidence suggests that large amounts of bitumen und the worle (Hutton et al., 1980)and oil-prone macerals (Price and The SPi is relevant only where a pod of active source Barker, 1985)retard the normal increase of vitrinit rock has been established. The entire source rock interva poor polishing, whereas high values are typical of spaced intervals using rock-Eval pyrolysis Samples that oxidized vitrinite by substantial caving should be avoided. Gross thickness Ro Histograms of the source rock must be corrected for well deviation structural complexities, and significant hydrocarbon generative potential (S1+S2<2 reflectance measurements determined on about 50-100 mg HC/g rock) to get net source rock thickness. The vitrinite particles in each polished kerogen preparation. samples should be representative of the organic facies in histogramsRo versus depth plots use the random mean contamination or migrated oil(Chapter Appendix B)and value and refer only to the population of organic particles should be from thermally immature or early mature identified by the analyst as vitrinite. Likewise, the standard deviation for these Ro values represents the portions of the source rock. SPI values determined from thermally mature or postmature sections can be low repeatability by which the analyst can select these because of petroleum expulsion. Although specific particles Because Ro values based on fewer than 50 source rock densities should be used, a density of 2 particles can be unreliable, we recommend that Ro t/mis used for most SPI calculations isograms be examined for all samples Laterally drained petroleum systems tend to accumu-
5. Applied Source Rock Geochemistry 101 Several factors based on the experience of the analyst are weighed in the process of selecting vitrinite particles. Ro trends established above and below the sample can be used to eliminate certain populations of macerals from consideration. Because TAI and RQ are related (Jones and Edison, 1978), a measured TAI can be used to estimate the R0 of the vitrinite population. This process is not always reliable, however, because TAI is commonly measured on less than a dozen palynomorphs and these might represent recycled organic matter or contamination from drilling mud. Reliability of RQ measurements from single samples increases when supported by independent maturity parameters (e.g., TAI and Tmax) and R0 versus depth trends established by multiple samples in a well. For example, Tmax can be used to support R„, particularly in the thermally mature stage. In situ vitrinite in some samples can be overwhelmed by recycled (high maturity) or caved (low maturity) particles. Selection of these particles as the "true" vitrinite might result in anomalous values compared to the R<, trend established by samples from other depths. As an extreme example, some Alaskan wells show little change or even a decrease in RQ with increasing depth at shallow well depth due to shedding of recycled (high R<,) organic matter from Mesozoic highlands into thermally "cool" Tertiary basins. Ro cannot be measured in rocks that lack vitrinite. Vitrinite is derived from land plants and is not common in rocks older than Devonian because abundant land plants had not yet evolved. Reflectance can be measured on graptolites in lower Paleozoic rocks (Link et al., 1990). Some oil-prone source rocks that formed on broad marine carbonate shelves (e.g., Jurassic of Saudi Arabia) or in large lakes (e.g., Lower Cretaceous of West Africa) contain only small amounts of vitrinite due to limited terrigenous organic matter input. The reflectance of solid bitumen has been calibrated to R0 and is particularly useful in vitrinite-poor carbonate rocks (Jacob, 1989). Evidence suggests that large amounts of bitumen (Hutton et al., 1980) and oil-prone macerals (Price and Barker, 1985) retard the normal increase of vitrinite reflectance with maturity. Low R<, values can result from poor polishing, whereas high values are typical of oxidized vitrinite. Ro Histograms R„ histograms show the frequency distribution of reflectance measurements determined on about 50-100 vitrinite particles in each polished kerogen preparation. The random mean R0 is determined from these histograms. RQ versus depth plots use the random mean value and refer only to the population of organic particles identified by the analyst as vitrinite. Likewise, the standard deviation for these R0 values represents the repeatability by which the analyst can select these particles. Because R0 values based on fewer than 50 particles can be unreliable, we recommend that R0 histograms be examined for all samples. Reflectograms Reflectograms (Figure 5.3) are frequency plots of the reflectance of all macerals measured in the polished kerogen slide. Unlike RQ histograms, reflectograms may provide an idea of the difficulty in selecting vitrinite particles for measurement. Selection of the correct particles for measurement may be difficult when there is no clearly predominant population of telocollinite (Figure 5.3). R0 must be determined using vitrinite because other macerals mature at different rates (e.g., Dow, 1977b). However, R0 can be extrapolated from reflectance measurements of some macerals other than telocollinite, such as exinite (Alpern, 1970). INTERPRETIVE TECHNIQUES Source Potential Index During the source rock assessment phase of sedimentary basin evaluation, geologists commonly rely on the quantity, type, and thermal maturity of organic matter as criteria to indicate favorable risk for significant petroleum charge. However, source rock volumetrics (thickness and lateral extent) must not be ignored. An oil-prone source rock dominated by type I or II kerogen and showing excellent genetic potential (e.g., S\ + S2 > 10 mg HC/g rock) may be too thin to charge economically significant oil accumulations. Source potential index (SPI) (Demaison and Huizinga, 1991) is defined as the quantity of hydrocarbons (metric tons) that can be generated in a column of source rock under one square meter of surface area (Demaison and Huizinga, Chapter 4, this volume). SPI (or "cumulative hydrocarbon potential," according to Tissot et al., 1980) is a simple method for ranking source rock productivity because it integrates both source rock richness and thickness. A relative source rock ranking system has been developed by compiling the average SPI values for source rock units from around the world. The SPI is relevant only where a pod of active source rock has been established. The entire source rock interval must be sampled and systematically logged at closely spaced intervals using Rock-Eval pyrolysis. Samples that were positively picked (Chapter Appendix B) or affected by substantial caving should be avoided. Gross thickness of the source rock must be corrected for well deviation, structural complexities, and nonsource units lacking significant hydrocarbon generative potential (Si + S2 < 2 mg HC/g rock) to get net source rock thickness. The samples should be representative of the organic fades in the area of interest. Samples should show no evidence of contamination or migrated oil (Chapter Appendix B) and should be from thermally immature or early mature portions of the source rock. SPI values determined from thermally mature or postmature sections can be low because of petroleum expulsion. Although specific source rock densities should be used, a density of 2.5 t/m3 is used for most SPI calculations. Laterally drained petroleum systems tend to accumu-
Peters and cassa late petroleum from larger drainage areas compared to Lawrence, 1990; Hester et al., 1990). These methods vertically drained systems. For this reason, lower limits most reliable within small areas where wireline response are used to define SPI categories for laterally drained has been calibrated to geochemical data systems (low, SPI 2; moderate, 2 s SPI <7; high, SPI2 Geochemical logs for eight exploratory wells are 7)than for vertically drained petroleum systems (low, included to show their usefulness for detecting free SPI 5; moderate 5 s SPI 15 high, SPI2 15)(see figure hydrocarbons and identifying source rocks. The first 4.4 of Lewan, Chapter 4, this volume) three geochemical logs(Figures 5.4-5.6)are from three SPI is a measure of the petroleum potential of a source wells (, Il, and Im) that are in the same area and demon- rock and ideally is determined from thermally immature strate the lateral continuity of two different source rocks rock. After a source rock shows a favorable SPI rating, The last five geochemical logs(Figures 5.7-5. 11)are from maps of SPl and thermal maturity are used to evaluate wells that are in different areas, but are used as examples which areas of a basin have the highest petroleum of different ways to identify and evaluate a source rock harge. Areas with the highest charge are most likely to be nearest the source rock where it is the most thermally Wells I through Ill mature, or nearest the pod of active source rock. The high-quality geochemical log for well I is based Conversely,areas most likely to have the lowest charge on closely spaced Rock-Eval pyrolysis and Toc data rthest from t the pod of active source rock. Whether this charge is supplemented by vitrinite reflectance(Figure 5.4) mostly gas or mostly oil is determined from the ker Closely spaced samples allow a critical evaluation of source and reservoir rock intervals (note the wider Chapter 4, this volume) provide a complete discussion of sample spacing in the C formation, a Lower Cretaceous migration drainage and entrapment styles for different rock). The penetrated section contains t troleum systems and show how to estimate the SPI for source rocks. The Upper Cretaceous B formation source source rocks, even when they have undergone thermal rock interval at 780-1540 m is a potential source rock that aturation beyond the immature stage has the capacity to generate significant quantities of oil (SPI=42 t HC/m2). The Tmax versus depth trend is Mass Balance calculations slightly depressed through this interval, probably because this sulfur-rich kerogen undergoes thermal Mass balance calculations, either by accumulation(or degradation at lower temperatures than many type II kerogens. Because the Lower Cretaceous is at maximum prospect)or petroleum system, can be used to provide burial depth, the F formation source rock at 3120-3620m another comparison of the amount of petroleum generated with the amount that has accumulated. The is an active source rock that is presently generating oil geochemical data for screening can also be used for SPI (SPI28tHC/m2). The production or productivity index calculations(Demaison and Huizinga, Chapter 4, this (PD gradually increases below about 3200 m, reflecting volume)and for mass balance calculations as suggested the onset of generation, which is also indicated by Tmax by Schmoker( Chapter 19, this volume), whose technique and Ro data. Vitrinite is generally absent in the carbonate is used in many of the case studies in this volume section and in the strata containing particularly hydrogen-rich kerogen. PI anomalies(e.g, at 100-600 m and 1600-3050 m) are"mathematical artifacts caused by EXAMPLES relatively low Sz yields where Sn yields may be slightly elevated by small quantities of organic drilling additives or minor shows. The F formation pe Geochemical logs are among the most valuable tools resel ntly an active source rock. for basin analysis, yet few examples are given in the liter The geochemical log for well ll, which is located in the ature(e. g, Clementz et al., 1979; Espitalie et al., 1977 same basin about 120 km southeast of well I (Figure 5.5), 1984, 1987; Peters, 1986; Magoon et al., 1987, 1988). shows that the Upper Cretaceous potential source rock is Proper use of geochemical logs allows identification of thicker than in well I. This potential source rock is still the following features in penetrated intervals immature and shows a similar source potential index Occurrence of potential, effective, and spent as well (SPI= 40 t HC/m2)to that in well I. The Lower Creta ceous source rock in well Ii is thicker and shows more as active and inactive source roc discre ete zones of higher and lower source potential than m in well L. The total thickness of the lower cretaceous interval in well ll is 700 m, but the net source rock postmature)zones thickness is only about 550 m and shows an SPI of 25 t Occurrence of varying amounts of in situ and HC/m2. Only the deeper portions of the Lower Creta- eous source rock are actively generating petroleum (because the onset of petroleum generation for this When geochemical logs are unavailable, geophysical source rock occurs at 0.6% Ro). Stratigraphically equiva- wireline logs and interpretive liques can be used lent Lower Cretaceous source rocks buried more deeply qualitative indicators of organic content (e.g, Passey et adjacent to this trap are the probable source for hydro- al., 1990; Schmoker and Hester, 1983; Stocks and carbon shows in the lower cretaceous sandstone in well
202 Peters and Cassa late petroleum from larger drainage areas compared to vertically drained systems. For this reason, lower limits are used to define SPI categories for laterally drained systems (low, SPI < 2; moderate, 2 < SPI < 7; high, SPI > 7) than for vertically drained petroleum systems (low, SPI < 5; moderate, 5 < SPI < 15; high, SPI > 15) (see figure 4.4 of Lewan, Chapter 4, this volume). SPI is a measure of the petroleum potential of a source rock and ideally is determined from thermally immature rock. After a source rock shows a favorable SPI rating, maps of SPI and thermal maturity are used to evaluate which areas of a basin have the highest petroleum charge. Areas with the highest charge are most likely to be nearest the source rock where it is the most thermally mature, or nearest the pod of active source rock. Conversely, areas most likely to have the lowest charge are farthest from the mature source rock, or farthest from the pod of active source rock. Whether this charge is mostly gas or mostly oil is determined from the kerogen type and maturity. Demaison and Huizinga (1991; Chapter 4, this volume) provide a complete discussion of migration drainage and entrapment styles for different petroleum systems and show how to estimate the SPI for source rocks, even when they have undergone thermal maturation beyond the immature stage. Mass Balance Calculations Mass balance calculations, either by accumulation (or prospect) or petroleum system, can be used to provide another comparison of the amount of petroleum generated with the amount that has accumulated. The geochemical data for screening can also be used for SPI calculations (Demaison and Huizinga, Chapter 4, this volume) and for mass balance calculations as suggested by Schmoker (Chapter 19, this volume), whose technique is used in many of the case studies in this volume. EXAMPLES Geochemical Logs Geochemical logs are among the most valuable tools for basin analysis, yet few examples are given in the literature (e.g., Clementz et al., 1979; Espitalie et al, 1977, 1984, 1987; Peters, 1986; Magoon et al., 1987, 1988). Proper use of geochemical logs allows identification of the following features in penetrated intervals: • Occurrence of potential, effective, and spent as well as active and inactive source rocks • Main stages of thermal evolution: diagenesis (immature), catagenesis (mature), and metagenesis (postmature) zones • Occurrence of varying amounts of in situ and migrated petroleum When geochemical logs are unavailable, geophysical wireline logs and interpretive techniques can be used as qualitative indicators of organic content (e.g., Passey et al., 1990; Schmoker and Hester, 1983; Stocks and Lawrence, 1990; Hester et al., 1990). These methods are most reliable within small areas where wireline response has been calibrated to geochemical data. Geochemical logs for eight exploratory wells are included to show their usefulness for detecting free hydrocarbons and identifying source rocks. The first three geochemical logs (Figures 5.4-5.6) are from three wells (I, II, and III) that are in the same area and demonstrate the lateral continuity of two different source rocks. The last five geochemical logs (Figures 5.7-5.11) are from wells that are in different areas, but are used as examples of different ways to identify and evaluate a source rock. Wells I through III The high-quality geochemical log for well I is based on closely spaced Rock-Eval pyrolysis and TOC data supplemented by vitrinite reflectance (Figure 5.4). Closely spaced samples allow a critical evaluation of source and reservoir rock intervals (note the wider sample spacing in the C formation, a Lower Cretaceous reservoir rock). The penetrated section contains two source rocks. The Upper Cretaceous B formation source rock interval at 780-1540 m is a potential source rock that has the capacity to generate significant quantities of oil (SPI = 42 t HC/m2). The Tmax versus depth trend is slightly depressed through this interval, probably because this sulfur-rich kerogen undergoes thermal degradation at lower temperatures than many type II kerogens. Because the Lower Cretaceous is at maximum burial depth, the F formation source rock at 3120-3620 m is an active source rock that is presently generating oil (SPI > 81 HC/m2 ). The production or productivity index (PI) gradually increases below about 3200 m, reflecting the onset of generation, which is also indicated by Tm^ and RQ data. Vitrinite is generally absent in the carbonate section and in the strata containing particularly hydrogen-rich kerogen. PI anomalies (e.g., at 100-600 m and 1600-3050 m) are "mathematical artifacts" caused by relatively low S2 yields where Si yields may be slightly elevated by small quantities of organic drilling additives or minor shows. The F formation penetrated in well I is presently an active source rock. The geochemical log for well II, which is located in the same basin about 120 km southeast of well I (Figure 5.5), shows that the Upper Cretaceous potential source rock is thicker than in well I. This potential source rock is still immature and shows a similar source potential index (SPI = 40 t HC/m2 ) to that in well I. The Lower Cretaceous source rock in well II is thicker and shows more discrete zones of higher and lower source potential than in well I. The total thickness of the Lower Cretaceous interval in well II is 700 m, but the net source rock thickness is only about 550 m and shows an SPI of 25 t HC/m2 . Only the deeper portions of the Lower Cretaceous source rock are actively generating petroleum (because the onset of petroleum generation for this source rock occurs at 0.6% RJ. Stratigraphically equivalent Lower Cretaceous source rocks buried more deeply adjacent to this trap are the probable source for hydrocarbon shows in the Lower Cretaceous sandstone in well