The petroleum system concept is a reliable and logical way to judge and describe the petroleum potential and exploration risks of undrilled propects, plays, and basins. In 19 chapters on petroleum system basics and 18 case study chapters, this comprehensive volume provides an integrated look at the processes of petroleum generation in active source rocks, migration, and accumulation in traps.
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Depositional environment is the dominant factor in determining the types of organic matter found in a rock. Only two types of organic matter are found in rocks: land derived and aquatic algae derived. Heat and pressure convert organic matter into a substance called humin and then into kerogen. Time and temperature convert kerogen into petroleum.
Geochemists define kerogen as the fraction of sedimentary organic constituent of sedimentary rocks that is insoluble in the usual organic solvents. Kerogens are composed of a variety of organic materials, including algae, pollen, wood, vitrinite, and structureless material. The types of kerogens present in a rock largely control the type of hydrocarbons generated in that rock. Different types of kerogen contain different amounts of hydrogen relative to carbon and oxygen. The hydrogen content of kerogen is the controlling factor for oil vs. gas yields from the primary hydrocarbon-generating reactions.
The type of kerogen present determines source rock quality. The more oil prone a kerogen, the higher its quality. Four basic types of kerogen are found in sedimentary rocks. A single type or a mixture of types may be present in a source rock. The table below lists and defines these four basic kerogen types.
Based on Figure 1, we determine that at a depth of length::2.6 km the modeled well is presently in the oil generation zone and approximately 25% of the kerogen in the source rocks at this depth has generated hydrocarbons. We know from the hydrocarbon generation-maturity relationship that at length::2.6 km this well has a vitrinite reflectance ( Ro) of 0.7%. If another well in the basin contains similar source rocks and has a maturity of 0.7% Ro at length::3.7 km, then we can predict that the section at length::3.7 km is mature for liquid generation and has generated a liquid hydrocarbons, converting approximately 25% of its kerogen to hydrocarbons.
Before enumerating the criteria for discriminating kerogen types, it is important to consider the "mineral matrix effect." Some mineral (polar clay) constituents retard the release of hydrocarbons from powdered whole rock samples during Rock-Eval pyrolysis, under-evaluating the quantity, quality, and thermal maturation data. Although this factor, the mineral matrix effect, is well known to organic geochemists, it is frequently overlooked when interpreting Rock-Eval-dependent values used to determine kerogen type and organic facies. The mineral matrix effect occurs when polar clays react with polar organic molecules during the nonhydrous Rock-Eval procedure.
Pioneers of pyrolysis found that some minerals inhibit hydrocarbon expulsion during whole-rock pyrolysis and not during kerogen pyrolysis. The effect of different matrix constituents varies from strongest to weakest: illite > Ca-bentonite > kaolinite > Na-bentonite > calcium carbonate > gypsum. Variations in the mineral matrix effect related to organic richness occur in whole-rock samples with TOC values less than 10%.
Geological thermal maturation processes differ from those of Rock-Eval pyrolysis. Whole-rock Rock-Eval samples are heated rapidly in an anhydrous environment. Geological burial processes cause clays to undergo physical and chemical alteration usually preceding the slow and systematic thermal conversion (generation) of kerogen to petroleum. These changes occur in hydrous environments, which probably reduce the reactive capabilities of clays, usually before significant hydrocarbon generation has occurred. Nevertheless, some degree of mineral matrix effect probably does persist under geological conditions.
Kerogen type I is predominantly composed of the most hydrogen-rich organic matter preserved in the rock record. Often the organic matter is structureless (amorphous) alginite and, when immature, fluoresces golden yellow in ultraviolet (UV) light. A large proportion of type I kerogen can be thermally converted to petroleum and therefore is rarely recognizable in thermally mature or postmature rocks. Sometimes in thermally immature rocks, morphologically distinct alginite is structurally or chemically assignable to specific algal or bacterial genera. These organic-walled microfossils have high H/C values because they formed hydrocarbons biologically. Some examples of pure assemblages with type I kerogen properties include the following: (1) the lacustrine alga Botryococcus braunii, which sometimes retains its diagnostic cup-and-stalk colonial morphology and/or its unique chemical compound, botryococcane; (2) Tasmanites spp., which are low-salinity, cool water, marine algal phyto-plankton with unique physical features; and (3) the Ordovician marine organic-walled colonial microfossil Gloeocapsomorpha prisca, with its diagnostic physical appearance and unique chemical signature. Where kerogen type I is widespread, it is mapped as organic facies A. It usually forms in stratified water columns of lakes, estuaries, and lagoons.
Kerogen type I is concentrated in condensed sections where detrital sediment transport is low and primarily pelagic. Condensed sections occur in offshore facies of transgressive systems tracts in marine and lacustrine settings. Although this extension of terminology from marine to lacustrine environments may be unfamiliar at first, lacustrine rocks are formed by the same dynamic processes that form marine rocks (i.e., sediment supply, climate, tectonics, and subsidence), although changes in lake levels often reflect local changes in runoff, evaporation, and sediment basin filling rather than the global and relative sea level changes postulated for marine sediments.
In chemistry and geology, biomarkers are any suite of complex organic compounds composed of carbon, hydrogen and other elements or heteroatoms such as oxygen, nitrogen and sulfur, which are found in crude oils, bitumen, petroleum source rock and eventually show simplification in molecular structure from the parent organic molecules found in all living organisms. Essentially, they are complex carbon-based molecules derived from formerly living organisms. Each biomarker is quite distinctive when compared to its counterparts, as the time required for organic matter to convert to crude oil is characteristic. Most biomarkers also usually have high molecular mass.
Some examples of biomarkers found in petroleum are pristane, triterpanes, steranes, phytane and porphyrin. Such petroleum biomarkers are produced via chemical synthesis using biochemical compounds as their main constituents. For instance, triterpanes are derived from biochemical compounds found on land angiosperm plants. The abundance of petroleum biomarkers in small amounts in its reservoir or source rock make it necessary to use sensitive and differential approaches to analyze the presence of those compounds. The techniques typically used includes gas chromatography and mass spectrometry.
Petroleum biomarkers are highly important in petroleum inspection as they help indicate the depositional territories and determine the geological properties of oils. For instance; they provide more details concerning their maturity and the source material. In addition to that they can also be good parameters of age, hence they are technically referred to as "chemical fossils". The ratio of pristane to phytane (pr:ph) is the geochemical factor that allows petroleum biomarkers to be successful indicators of their depositional environments.
Geologists and geochemists use biomarker traces found in crude oils and their related source rock to unravel the stratigraphic origin and migration patterns of presently existing petroleum deposits. The dispersion of biomarker molecules is also quite distinctive for each type of oil and its source, hence, they display unique fingerprints. Another factor that makes petroleum biomarkers more preferable than their counterparts is because they have a high tolerance to environmental weathering and corrosion. Such biomarkers are very advantageous and often used in the detection of oil spillage in the major waterways. The same biomarkers can also be used to identify contamination in lubricant oils. However, biomarker analysis of untreated rock cuttings can be expected to produce misleading results. This is due to potential hydrocarbon contamination and biodegradation in the rock samples.
Fundamentals of Reservoir Rock Properties discusses several essential rock properties needed for petroleum engineers and geoscientists. The topics covered are porosity, rock compressibility, permeability, fluid saturation, electrical properties of reservoir rocks, wettability, capillary pressure, and relative permeability. The final chapter integrates all the properties with a discussion on the application. The book covers the topics in a step-by-step fashion with tons of illustrative figures. Each topic is presented clearly with a wide range of illustrations and simplified explanations.
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