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Tekst voor de cursus Grondstoffen en het Systeem Aarde (HD 698) H.E.Rondeel, december 2001
Teksten gebaseerd op: Blackbourn, G.A. (1990) Cores and core logging for geologists. Whittles Publ.,Caithness. 113 pp. Shauer Langstaff, C. & D. Morrill (1981) Geologic cross sections. IHRDC, Boston. 108 pp. Stoneley, R. (1995) An introduction to petroleum exploration for non-geologists. Oxford University Press, Oxford. 119 pp. Waples, D. (1981) Organic geochemistry for exploration geologists. Burgess Publ. Co., Mineapolis. 151 pp. Waples, D.W. (1985) Geochemistry in petroleum exploration. Reidel Publ. Co, Dordrecht & IHRDC, Boston. 232 pp.
Many of the chemical compounds present in sediments are in fact derived from bacteria. and thus eventually bring organic diagenesis to a halt. and were formed as dead organic matter was converted to microbial tissues. and are called bitumen . In the late stages of catagenesis and in the final transformation stage. the principal products consist of smaller gas molecules. Migration through these conduits often leads to traps. Once formed.5 1 . the largest of which are called kerogen. In recent years this relatively simple picture of hydrocarbon generation has been complicated slightly by our growing awareness that kerogens formed from different kinds of organic matter. The earliest stage of hydrocarbon generation occurs during diagenesis. As burial depth increases.Introduction FORMATI0N OF 0IL AND GAS Proponents of the organic origin of oil and gas have given us a general picture of how organic matter derived from dead plants is converted to hydrocarbons.Organic Facies . are chemically distinct from each other. Low-temperature chemical and biological reactions (called diagenesis) that occur during transport to and early burial in the depositional environment modify this organic matter. Formation of biogenic methane has been recognized for a long time. with many details still poorly understood. these are the precursors for petroleum. During this second transformation phase. more mobile molecules. These differences can have a significant effect on hydrocarbon generation. it is known that organic debris derived from plants and algae is best preserved in fine-grained sediments deposited in the absence of oxygen. In the early stages of catagenesis most of the molecules produced from kerogen are still relatively large. or under different diagenetic conditions. convert some of the organic debris to biogenic methane. porosity and permeability decrease. As temperature rises. however. These play a key role as the precursors for oil and much natural gas. where hydrocarbon movement ceases and accumulation occurs. oil and gas molecules can be expelled from the source rock into more permeable carrier beds or conduits. thermal reactions become increasingly important. These changes lead to a gradual cessation of microbial activity. . and temperature increases. called catagenesis. but only within the last few years have we realized that in many areas a large portion of the natura!-gas reserves are biogenic. Although the transformation process is very complex. kerogen begins to decompose into smaller. Certain microorganisms. called metagenesis. called methanogens. Most of this organic matter is transformed during diagenesis info very large molecules.
less than 1% of the annual photosynthetic production escapes from the carbon cycle and is preserved in sediments. Despite the great imbalance in biomass between terrestrial plants (450 billion metric tons [t]) and aquatic phytoplankton (5 billion t). Oxidative decay of dead organic matter is a highly efficient process mediated largely by microorganisms.Organic Facies THE CARBON CYCLE Because oil and gas are generated from organic matter in sedimentary rocks. Preservation of organic matter begins with photosynthesis. we need to understand how this organic matter came to be preserved in the rocks. Zooplankton and higher animals contribute relatively little organic matter to sediments. comprises microbial tissue formed within the sediments by the bacterial transformation of plant and algal debris. Because of .6 2 . The recently discovered deep-sea ecosystems in the Pacific Ocean that derive their energy from oxidation of sulfides in hydrothermal vents are interesting but volumetrically unimportant. as a consequence of the much more rapid reproduction of simple aquatic organisms. A large fraction.Organic Facies . Most organic carbon is returned to the atmosphere through the carbon cycle. however. Preservation of organic material is actually a rare event. the yearly productivity of both groups is about equal. Some of the organic material in sediments consists of fragments of plants or algae that derived their energy from the sun.
and general water chemistry. Total Organic Carbon (TOC) values decrease monotonically through the first 300 meters of burial before levelling out at about 0. PRODUCTIVITY A partial listing of the many factors influencing productivity would include nutrient availability. Each of these categories could in turn be further subdivided. On the other hand. There is another zone of seasonal upwelling off the Horn of Africa in the Indian Ocean as a result of .000. Although oxidative decay destroys most of the yearly production. over vast amounts of geologic time the small fraction that escaped the carbon cycle has built up extremely large quantities of organic matter (20. Although some destruction of organic material occurs during transport to the depositional environment. Each factor may be dominant under different conditions. with a preference for horizontal water movement within each density layer. however. orogeny and erosion. Upwelling occurs where bulk movement of surface water away from a particular area allows deeper water to ascend to replace it. a great deal of the oxidation of organic matter occurs within the sediments themselves. FACTORS INFLUENCING ORGANIC RICHNESS In order for organic-rich rocks to be formed. Namibia. are therefore much more productive than the open ocean. because under normal circumstances they cannot move upward into the zone of photosynthesis. Nutrients dissolved in waters below the photic zone therefore go unutilized.000 billion t) dispersed in fine-grained sedimentary rocks. or about 0.7 extensive oxidation of land-plant debris in soils.05%) occurs in economic deposits of fossil fuels. only one molecule out of about every one million successfully negotiates the journey from living organism to the gasoline pump. Peru. Shallowmarine environments. nutrient availability would depend on such factors as water circulation patterns. preservation. volcanism. and recycling by organic decay. where there is local recycling of nutrients from decaying organisms and influx of fresh nutrients from terrestrial sources. suggesting that either depth or organiccarbon content eventually limits diagenesis.1%. paleoclimate. Nutrient availability is. If this deeper water is enriched in nutrients. one of the critical parameters governing productivity. the low TOC values could indicate that the remaining organic matter has no more nutritional value.Organic Facies . In the modern world there are zones of intense seasonal upwelling off the west coasts of California. carbonate supply. The three primary factors influencing the amount of organic matter in a sedimentary rock are productivity. watercirculation patterns are particularly important for supplying nutrients and thus controlling productivity. and dilution. Depth could interfere with microbial diagenesis when compaction reduces pore sizes and nutrient fluxes in interstitial waters. and that the microbes have given up trying to digest it. Only where there is upwelling of subsurface waters can these nutrients return to the photic zone. When we consider inefficiencies in discovery and recovery. significant amounts of organic matter must be deposited and protected from diagenetic destruction. temperature. high photosynthetic productivity will occur at the site of upwelling. For example. Bodies of water naturally develop density stratification. Only a small fraction of this (10. In relatively unrestricted marine environments. and Northwest Africa that result from the movement of surface waters away from these coasts. because without adequate productivity. accumulation of organic-rich sediments cannot occur.000 billion t. Productivity is the logical place to begin our analysis. light intensity. much of the terrestrial organic material is already highly oxidized when it arrives in the sediments. in fact. predators.
2 mL/L is called the anoxic zone. Because most of the oxidation occurring in the water column. soils. the accuracy with which we can reconstruct continental positions. wind and water circulation patterns. productivity is probably not as important a factor as preservation. All these areas exhibit high productivity when upwelling occurs. PRESERVATION The principal control on organic richness is the efficiency of preservation of organic matter in sedimentary environments. The term dysaerobic has been used to describe processes occurring in the transitional zone (0. and sediments is biological. essentially the only viable organisms are those that we call anaerobes. These anaerobic processes are inefficient compared with aerobic diagenesis. Thus if anoxia can develop. however. and all the other factors that influence upwelling loci is severely limited. However.5 mL/L). Theoretical models have been developed to predict upwelling (and consequent productivity) in ancient seas from input data on continental configurations. some problems associated with their application. and paleoclimates. the simplest way to limit oxidation is to limit the supply of oxygen. because marine organic matter is consumed preferentially by organisms. if on the average only 1% of organic matter is preserved.2-0. Its presence in . Secondly. the remaining individuals often become dwarfed in an effort to survive in a hostile environment. Three factors affect the preservation (or destruction) of organic matter: the concentration and nature of oxidizing agents.2 mL/L. The presence of undegraded marine organic material is a strong indication of anoxia. Anoxic sediments always contain elevated TOC values (generally above 2% and always above 1% ). landmasses. and are usually limited in scope by the availability of sulfate or nitrate. and may in fact prove useful in future exploration efforts. microorganisms that utilize materials like sulfate or nitrate ions instead of molecular oxygen as electron acceptors in their metabolic processes. preservation of organic matter will be much enhanced. Such models are interesting. Anoxic sediments are not always easy to recognize. TOC values alone must therefore be used with caution. At dissolved oxygen levels below about 0. Processes that occur in these two zones are called aerobic and anaerobic. especially of woody origin. The term "anoxic" literally means "having no oxygen. many species disappear. ANOXIA. At lower levels of dissolved oxygen. because some of the commonly used indicators of anoxia may be misleading. respectively. its use in practice has been expanded to include very low oxygen levels as well. Of these. increasing preservation rates is a very efficient way to increase organic richness. the zone where oxygen falls below 0. paleoclimatic conditions.5 milliliters (mL) per liter (L)). and the sediment-accumulation rate." hut because of the radical change in biota that occurs at about 0. although some species can tolerate extremely low oxygen levels (0.2 mL/L. There are many more organic-rich facies resulting from excellent preservation than from extremely high productivity. and because most biological oxidation processes require molecular oxygen.Organic Facies . diagenesis is restricted to anaerobic processes. and we could coin the term dysoxic to describe the zone itself. All large organisms require oxygen in order to live. the type of organic matter deposited. We call the zone in which oxygen contents are high the oxic zone. Anoxia is of tremendous importance in the preservation of organic matter in sediments. because when the availability of oxygen is limited. After all. There are. especially in the Palaeozoic. First. oxidizing agents are probably the most crucial factor. much oxic sediment also contains large amounts of organic matter.8 monsoonal winds that drive surface waters away from the coast.
and strata from several basins in China. the presence of bioturbation indicates that the bottom waters were not anoxic. most likely by absence of oxygen. Among the ancient lake beds thought to have been deposited in permanently stratified waters are the well-known Green River Shale (middle Eocene. OXYGEN-MINIMUM LAYER (OML). are anoxic in some of the places where they have been penetrated. it cannot represent an anoxic facies. Although pyrite does indeed form under anoxic conditions. It therefore behoves us to understand the conditions under which anoxia develops. The supply of fresh oxygen is therefore limited to horizontal . The presence of pyrite itself can also be deceptive.Organic Facies . no more oxygen can enter. Nevertheless. This oxygen minimum develops when the rate of consumption of oxygen within that layer exceeds the rate of influx of oxygen to it. Marine basins are seldom isolated enough to fit well into the stagnant-basin model. particularly in understanding lacustrine beds. it may well have developed after burial. once the original oxygen has been consumed in oxidizing organic matter. Lakes in failed rifts can also contain organic-rich. anoxic sediments show preserved depositional laminae on a millimeter or submillimeter scale. The oxygen-minimum layer is a layer of subsurface water that has a lower dissolved-oxygen content than the water layers either above or below. The laminae prove that burrowing fauna were absent. anoxic sediments. Wyoming). and if the climate is subtropical or tropical. Lakes of the Rift Valley of East Africa are excellent modern analogs receiving much attention from both researchers and explorationists at the present time. The cooler. are not rich in organic carbon. The oxygen minimum layer usually begins immediately below the photic zone. slow circulation or turnover of the water column occurs almost everywhere. anoxia can be very local. they often owe their dark color to finely divided pyrite or to particular chert phases. the Elko Formation (Eocene/Oligocene. Many black rocks. Furthermore.9 rocks therefore indicates that diagenesis was stopped prematurely. although stunted burrows can be used as evidence of dysoxia. it is instructive to consider complete stagnation. Conversely. Depths in excess of 200 m are required to prevent mixing during storms. leading to the eventual development of a pycnocline (density interface) which prevents interchange between the two layers.2 mL/L. The ultimate implications of anoxia for petroleum exploration are great. denser waters remain at the bottom. If an isolated body of water is deep enough. intense pyritization of benthic bivalves is testimony to the fact that pyrite is not a good indicator of bottom-water anoxia at the time of deposition. Consumption of oxygen results from decay of dead organisms that have sunk from the photic zone above. Finally. and its presence indicates that the anaerobic reduction of sulfate ion did occur. Truly stagnant basins are actually quite rare. and both the waters in the bottom layer and the underlying sediments will become anoxic. it has been estimated. then permanent density stratification will arise as a result of temperature differences within the water column. and warm climates are necessary to avoid overturn caused by freeze-thaw cycles. where photosynthesis and turbulence can no longer contribute oxygen to the water. that most of the world's oil was generated from source beds deposited under anoxic conditions. Therefore. there is no guarantee that anoxia was present at the sea floor. Lake deposits associated with continental rifting. Color should be used mainly as a negative criterion: If a rock is not very. Nevada). All anoxic sediments will be very dark gray or black when deposited. very dark. however. STAGNANT BASINS. but limnic environments often are. especially during the Triassic along the margins of the developing Atlantic Ocean. Color is not a reliable indicator. Lack of communication between the layers prohibits replenishment of oxygen in the bottom layer. and therefore that dissolved-oxygen levels were below 0. in fact.
Late Devonian) the world oceans were severely depleted in dissolved oxygen. foreset beds within the same system are leaner in organic matter because they are deposited above the OML. Shallow Silling. Any organic matter arriving in those sediments will have an excellent chance to escape oxidation. those environments can also incorporate the features of an oxygen-minimum-layer model. Large amounts of organic material are preserved in coal swamps as a result of the combined effects of poor water circulation. Circulation is often restricted by the presence of a sill. Coal swamps can develop under a variety of conditions in both marine and non-marine environments. Although circulation in coal swamps is generally sluggish. RESTRICTED CIRCULATION. to a lesser extent.. Settings in which circulation is restricted are much more common than stagnant basins. Shallowly silled basins often yield evaporites. permanent density stratification will develop. because these horizontally moving waters also lie within the oxygen minimum layer. or as lateral facies equivalente thereof. and grazers and predatory organism are eliminated by the high salinities. sediments will be deposited under low-oxygen conditions. with the bottom layer almost isolated from the open-marine waters. the point of connection between the restricted area and the open-marine environment. its intensity varies greatly. In contrast. Where the sill is shallow. Evaporitic environments combine the opportunity for abundant growth of algae with ideal conditions for preservation. Wherever an intensely developed OML intersects the sediment-water interface. It is not coincidental that these were times of deposition of large amounts of organic-rich rocks in many parts of the world. Intensely developed OMLs occur in areas of high productivity and.10 movement of oxygen-bearing waters. the shallowness of the swamps prevents the waters themselves from becoming anoxic. In times like the mid-Cretaceous. This depletion was probably the result of the complex interplay of several factors. The result is often deposition of organic-rich laminae within evaporites. Nutrients are concentrated by evaporation. These include the modern Peru-Chile shelf (high productivity associated with upwelling) and occurrences of black sediments of Aptian to Turonian age in the North Atlantic. Coal Swamps.g. Late jurassic. since most organic matter was destroyed within the overlying OML. because of their connection with the open-marine realm. Anoxia . High productivity reduces oxygen levels. During those times the OML expanded both upward and downward because of poor supply of oxygen to subsurface waters. and high hydrogen-sulfide concentrations create conditions poisonous to predators. and diminished bacterial activity. high influxes of organic matter.Organic Facies . Bottomset beds associated with prograding delta systems can be rich in organic matter if they are laid down within a well-developed oxygen-minimum layer. the waters entering or leaving the basin are near surface. whereas in a fluvially dominated system (Black Sea) the net flow of surface water is out over the sill. Although an oxygen-minimum layer exists virtually everywhere in the ocean. as a result of diminished oxygen demand. In either case. including paleoclimate and water circulation. In actuality there is a lazy turnover of the bottom waters. In an evaporitic environment (Karabogaz in the Caspian Sea) there is a net flow of water into the basin. mid-Cretaceous. but it is too slow to disturb the anoxia which develops in the bottom layer. Furthermore. There are other ancient and modern examples of organic-rich rocks deposited under anoxic or near-anoxic conditions associated with OMLs. However. if the basin is deep enough. in areas of poor circulation. an upward expansion of the OML led to a tremendous increase in the surface area covered by anoxic bottom waters. Below the OML oxygen levels again increase. which could be excellent hydrocarbon source rocks. the oxygen they can contribute is limited. when a major transgression had greatly increased the continental shelf area. It has been proposed that at certain times in the past (e.
at very high accumulation rate dilution may become a more important factor than increased preservation. but it does spread that organic material through a larger volume of rock. Coals also accumulate very rapidly and. thus preventing extensive diagenesis of such material. Most depositional settings not specifically catalogued above will be more or less well oxygenated. renders it of little nutritional value. the phenolic components present in lignin-derived terrestrial material are toxic to many micro-organism. The hydrocarbon-source potential of all of these oxidizing facies is low. cuticular. Furthermore. .11 develops within the sediments rather than in the water column. DILUTION Although high sediment-accumulation rates enhance preservation of organic matter. and therefore wi11 contain primarily oxidized organic matter. especially in structural (woody) material. but their supposedly low potential for generating oil is to be reconsidered. because extensive decomposition occurs during its fall to the ocean floor. because its chemical components are digestible and provide precisely the nutrients required by scavengers and predators. with their high concentrations of organic matter.Organic Facies . TOC values increase as sediment-accumulation rates increase. provide an ideal means of maintaining low-oxygen conditions. as a result of more rapid removal of organic material from the zone of microbial diagenesis. Lack of sulfate in non-marine swamps further prevents anaerobic microbial destruction of the organic matter. and more favorable for gas than for oil. In fact. The net result is a reduction in TOC values. Any extensive organic diagenesis is therefore likely to eliminate algal organic matter first. or resinous material. It may also contain very resistent organic debris derived from erosion of ancient rocks. Organic matter of algal (phytoplanktonic) origin is consumed more readily by organisms than are other types of organic material. Rapid deposition of inorganic detritus is common in turbidites and in prodelta shales. Rapid settling of organic debris through the water column is also important. and low productivity in the overlying pelagic realm. which settle several orders of magnitude faster than individual phytoplankton. their virtual absence in much terrestrial organic material. The extremely high accumulation rates for biogenic carbonates and siliceous sediments in zones of high productivity promote preservation of the associated algal protoplasm. Oxic Settings. Abyssal sediments are notoriously low in organic carbon as the result of the combined effects of high oxygen levels in abyssal waters. biogenic inorganic sediment. Nitrogen and phosphorus are in particular demand. Near-shore oxidizing facies sometimes have high TOC values. That material which remains is dominantly of terrestrial origin. Dilution does not reduce the total amount of organic matter preserved. but the organic material is almost invariably woody. Rapid burial is accomplished by a high influx of inorganic detritus. Coals are important source rocks for gas accumulations. RAPID SEDIMENTATION AND BURIAL. and may include woody. very slow sedimentation rates. all of which are chemically quite distinct from each other. Phenolic bactericides derived from lignin hinder bacterial decay in the water and throughout the sediment column. or organic material. cellulosic. Rapid sedimentation and burial con also enhance preservation. and other oxidative processes. much of the organic material that does reach the bottom in deep waters arrives in relatively large fecal pellets. forest fires. TYPE OF ORGANIC MATTER. lignitic.
as a result of high productivity or sluggish circulation. however. Productivity can be predicted by locating ancient sites of marine upwellings. a strongly developed oxygen-minimum layer. . Facies changes from carbonates to shales may create large dilution effects that can be wrongly interpreted as indicating changes in oxygen levels. and the presence of high TOC values coupled with the occurrence of undegraded marine organic matter. effectiveness of preservation. It is important to be able to distinguish local anoxia or anoxia developed deep within sediments from anoxia induced by anoxic bottom waters. Rapid accumulation of sediment shortens the residence time of organic matter in the zone of diagenesis and thus promotes preservation.Organic Facies . Some of the commonly applied criteria are apt to be misleading. anoxic sediments were deposited discontinuously through time and space.and atmospheric-circulation patterns. and a very imperfect understanding of oceanic. Preservation is best accomplished where oxygen is excluded from bottom waters. Models that integrate the concepts of organic richness with depositional cycles and facies analysis will be valuable tools for understanding hydrocarbon systems in basins. in contrast. such events were often interrupted for long periods before anoxia was reinduced. To derive maximum value from our analyses. we should always strive to place the organic rich rocks in the larger context of basin evolution through time and space. where sediment-accumulation rates are directly proportional to organic-carbon-accumulation rates. and rapid burial. Because of its role in creating rocks with excellent hydrocarbon-source potential. however. dilution is far less marked.12 Dilution effects depend upon rock lithology. including stagnancy or near-stagnancy. in contrast. lack of knowledge of seawater chemistry and nutrient availability at those times. and dilution by inorganic material. In biogenic sediments or coals. such models are not yet of much practical value for the distant past. however. There are a number of mechanisms by which oxygen depletion may be fostered and maintained. in which the organic and inorganic materials arrive together. by uncertainties about exact continental positions and configurations in the past. Anoxic events in the past were probably not as large in scale or as long lasting as some workers have suggested. preservation is generally the most important. anoxia in bottom waters is a phenomenon whose effects we should learn to recognize in ancient rocks. show strong dilution effects when accumulation rates are very high. Of these. SUMMARY There are three principal factors that affect the amount of organic matter in sedimentary rocks: primary photosynthetic productivity. Consequently. It is often very difficult to separate the influences of these various factors in a particular depositional environment. dilution effects may lead to lower TOC values in spite of enhanced preservation rates. are not as strongly affected by dilution. Direct control of the anoxia was thus probably local. As in the modern oceans. The most reliable criteria for bottom-water anoxia are the preservation of fine depositional laminae. Although certain periods undeniably contain more than their share of anoxic rocks. Shales. Our ability to make accurate predictions is limited. Biogenic sediments. If the rapidly accumulating sediment is mainly clastic.
Examples of hydrocarbons are methane. using a subscript on the H to denote the total number of hydrogens around that atom. We can make other logical simplifications for longer carbon chains.Organic Chemistry .Organic Chemistry INTRODUCTION Anyone who uses petroleum geochemistry must be familiar with basic chemical terminology. NAMES AND STRUCTURES HYDROCARBONS In chemical terms a hydrocarbon is a compound containing only the elements carbon and hydrogen. All compounds containing carbon atoms. One common convention is to represent all the hydrogen atoms attached to a given carbon atom by a single H. If one wants to draw large molecules. The objective of this chapter is to acquaint the reader with the names of common compounds and with several different conventions for drawing their structures. In each of these compounds. The following representations of n-pentane are equivalent: CH3CH2CH2CH2CH3 or CH3(CH2)3CH3." but that usage is incorrect trom the chemist's point of view because those materials often contain substantial amounts of nitrogen. and organic geochemistry the study of organic compounds present in geological environments. in which one must also learn all the reactions of many classes of compounds. and nitrogen. carbonates. Petroleum and natural gas are themselves often referred to as "hydrocarbons. sulfur. Several different types of shorthand have therefore developed to facilitate drawing organic molecules. and cyclohexane. whose structures are shown below. hydrogen always forms one bond.13 3 . especially if one has to do it only occasionally. three bonds. elsewhere in this text usage will vary. except carbon dioxide. the explicit inclusion of every atom and every bond becomes extremely tedious. as it does in the real world. . In this chapter we restrict the usage of the term hydrocarbon to the standard chemical one. and indeed in every carbon compound (except a few highly unstable ones created only in laboratories). every carbon atom forms four bonds. however. oxygen and sulfer. This unique property of carbon is responsible for the existence of literally millions of different organic compounds. This usage is historical and does not imply that all such compounds are necessarily derived from living organisms. and metal carbides. Organic chemistry is thus the study of carboncontaining compounds. are termed organic. and other elements. The chemical reactions of interest to us are very few and are discussed only briefly. Carbon atoms like to form bonds with each other. creating long chains and ring structures. ethane. Similarly. oxygen. This objective is very different trom that of a normal course in organic chemistry. The structures of methane and ethane are thus represented by CH4 and CH3CH3 respectively. trace metals. two bonds. Writing the detailed structure of a simple molecule like methane is no problem.
For example. which. That is. Another important group of hydrocarbons is the unsaturates.14 An even quicker shorthand that uses no letters at all has evolved. Each carbon atom is represented by a point. Many unsaturated compounds have carbon-carbon double . Branching can occur. In the case of 2methylhexane (C7H16) the basic structure is hexane. no more hydrogen can be incorporated into the molecule without breaking it apart. in contrast. The zigzag configuration illustrated for n-pentane is adopted to show clearly each carbon atom. giving rise to a vast number of possible structures. Among the most important branched hydrocarbons in organic geochemistry are the isoprenoids. n-pentane and cyclohexane are represented by the line structures shown below. the names of the other nine simplest n-alkanes are given in the following table. Hydrogen atoms and bonds to hydrogen atoms are not shown at all. because they are saturated with respect to hydrogen. Names and formulas of the ten smallest n-alkanes Methane CH4 CH4 Ethane C2H6 CH3CH3 Propane C3H8 CH3CH2CH3 Butane C4H10 CH3 (CH2)2 CH3 Pentane C5H12 CH3 (CH2)3 CH3 Hexane C6H14 CH3 (CH2)4 CH3 Heptane C7H16 CH3 (CH2)5 CH3 Octane C8H18 CH3 (CH2)6 CH3 Nonane C9H20 CH3 (CH2)7 CH3 Decane C10H22 CH3 (CH2)8 CH3 Carbon atoms need not always bond together in a linear arrangement. is the adjectival form of the word methane. and indicates that there is no branching in the carbon chain. The letter n stands for normal. Note that the name of each compound ends in -ane. a CH3 (methyl) group is attached to the second carbon atom. are able to combine with additional hydrogen. which we used earlier. All the compounds mentioned above are called saturated hydrocarbons or saturates. ethyl and propyl). These cyclic compounds (called naphthenes) are named by counting the number of carbon atoms in the ring and attaching the prefix cyclo. simple inspection shows how mant' hydrogen atoms each carbon atom must have. as in "alkane. We have also seen that carbon atoms can be arranged in rings." The first four names are irregular. Isoprenoids ranging in length from six to forty carbon atoms have been found in petroleum and rocks. these molecules are called n-alkanes or nparains. We have ahready encountered n-pentane. but the prefixes denoting the number of carbon atoms in the other alkanes are derived from Greek numbers. The simplest series of hydrocarbons has linear structures. and carbon-carbon bonds are shown as lines connecting those points. The term methyl.Organic Chemistry . Because we know that each carbon atom forms four bonds and each hydrogen atom forms one bond. Regular isoprenoids consist of a straight chain of carbon atoms with a methyl branch on every fourth carbon. Other adjectival forms are made by dropping the -ane ending and adding yl (for example.
except that the ending -ene indicates the presence of a double bond. Most biological molecules are larger and more complex than the simple hydrocarbons. In fact. Although they are unsaturated. Among the most important NSO compounds are the asphaltenes. The hydrocarbons present in petroleum are mostly the end products of extensive degradation of biogenic molecules. It is this delocalization of electrons which makes aromatic compounds very stable. Some aromatic molecules are very large. these compounds are quite different trom the majority of the organic molecules found in living organisms. Fossil organic matter often contains a vide variety of heterocompounds. NONHYDROCARBONS Atoms other than hydrogen and carbon that occur in petroleum. The hydrocarbons we discussed so far are relatively simple molecules. Their stability permits aromatics to be important constituents of oils and sediments. and oxygen. and kerogen are called heteroatoms. bitumen. By hydrogenation ethene thus reacts to form ethane. They are named in a similar manner to the alkanes. The extreme case is graphite. because the most common heteroatoms are nitrogen. they do not long persist in geologic environments. these compounds are called alkenes. converts alkenes to alkanes and cyclic compounds during diagenesis. sulfur. A simplified notation for drawing these molecules permits us to represent the double-bond system by a circle within the ring. Many common NSO compounds are not directly related to biogenic precursors. which are large. the structures of which are shown below. some complex hydrocarbons that are found in fossil organic material can be related directly to individual biological precursors.Organic Chemistry . propene (C3H6). they do not add hydrogen easily. which is an almost-endless sheet of aromatic rings. Aromatics possess a system of alternating single and double bonds within a cyclic structure. Although they are very important constituents of petroleum. that is. highly aromatic materials of . the majority contain oxygen. they are free to move throughout the cyclic system instead of being held between two particular carbon atoms. Heterocompounds are also called NSO compounds. Polycyclic aromatic hydrocarbons having fused ring structures are quite common. In the laboratory they are readily converted to alkanes by the addition of hydrogen in the presence of a catalyst. Many of the heterocompounds present in organisms are converted to hydrocarbons during diagenesis and catagenesis. At first glance aromatics appear to be nothing more than cyclic alkenes containing several double bonds.15 bonds. Examples are ethene (C2H4) . phosphorus. the compounds in which they occur are called heterocompounds. sulfur. or other elements. Because alkenes are highly reactive. A variety of reactions. Aromatics form an extremely important class of unsaturated hydrocarbons. including hydrogenafion. and cyclohexene (C6H10). but they actually have completely different chemical properties from alkenes and are unusually stable. of which some are biogenic and others are formed during diagenesis. nitrogen. The circle indicates that the electrons in the double bonds are delocalized.
and thus are seldom preserved in sediments (exceptions occur in shell material and in bones. Because phenols are potent bactericides. Amino acids are the building blocks of proteins. Many nonhydrocarbon molecules common to living organisms are also present in sediments. They are rapidly metabolized by virtually all organisms. They have many characteristics in common with kerogen.16 varying structure. where small amounts of preserved amino acids can be used to date specimens) . Lignin monomers are linked topether to form molecules having molecular weights from 3000 to 10. Upon decomposition lignin forms phenolic compounds. Like lignin. it is an important constituent of terrestrial organic matter. Carbohydrates include starch. sugars. but asphaltene molecules are smaller and more aromatic than most kerogens. Among these are lignin. carbohydrates.Organic Chemistry . Although cellulose is quite resistant to decomposition under some conditions. lignin is rather resistant to degradation. and cellulose. It is a polymer consisting of many repetitions and combinations of three basic aromatic subunits. however. most carbohydrates are attacked readily by microorganisms. the latter is the most abundant organic compound in the biosphere. and amino acids. and thus tends to become concentrated as other organic matter is decomposed. providing much of the structural support for large land plants. which are aromatics having a hydroxyl group (OH) attached. Lignin is an important component of wood. Lignin and cellulose are major constituents of humic coals.000 atomic mass units.
The smallest of these geopolymers are usually called fulvic acids. which have molecular weights of several thousand or more. Kerogen is of great interest to us because it is the source of most of the oil and some of the gas that we exploit as fossil fuels. Lack of solubility is a direct result of the large size of kerogen molecules.Kerogen . in contrast.Kerogen INTRODUCTION Kerogen is normally defined as that portion of the organic matter present in sedimentary rocks that is insoluble in ordinary organic solvents. the geopolymers become larger. humins. and less regular in structure. Subsurface heating causes chemical reactions that break off small fragments of the kerogen as oil or gas molecules. and sediments. develop after tens or hundreds of meters of burial. oil. Today it is used to describe the insoluble organic material in both coals and oil shales. as well as the nature of the organic matter from which it was formed. The chemical and physical characteristics of a kerogen are strongly influenced by the type of biogenic molecules from which the kerogen is formed and by diagenetic transformafions of those organic molecules. have more mineral matter than algal coals. The term kerogen was originally coined to describe the organic matter in oil shales that yielded oil upon retorting. will be discussed in a following chapter. During the course of diagenesis in the water column. Large organic biopolymers of highly regular structure (proteins and carbohydrates. more complex. and still larger ones.17 4 . called bitumen. The residual kerogens also undergo important changes. If anaerobic sulfate . slightly larger ones. with some of the inorganic matrix often being contributed by the algae themselves. Kerogen composition is also affected by thermal maturation processes (catagenesis and metagenesis) that alter the original kerogen. Diagenetic and catagenetic histories of a kerogen. strongly influence the ability of the kerogen to generate oil and gas. Algal (boghead) coals are formed in environments where the source phytoplankton lack both calcareous and siliceous skeletal components. which are reflected in their chemical and physical properties. Diagenesis results mainly in loss of water. These geopolymers are the precursors for kerogen but are not yet true kerogens. soils. and the individual component parts are either destroyed or used to construct new geopolymers. and how much oil or gas can be expected. Coals are a subcategory of kerogen. Humic coals are best thought of as kerogens formed mainly from landplant material without codeposition of much mineral matter. for example) are partially or completely dismantled. because it has patchwork structures formed by the random combination of many small molecular fragments. and natural gas. The detailed chemistry of kerogen formation need not concern us greatly. KEROGEN FORMATION The process of kerogen formation actually begins during senescence of organisms. large molecules that have no regular or biologically defined structure. Each kerogen molecule is unique. as well as dispersed organic matter in sedimentary rocks. The soluble portion. and ammonia from the original geopolymers. Coals and oil shales should therefore be viewed merely as sedimentary rocks containing special types of kerogens in very high concentrations. A basic understanding of how kerogen is formed and transformed in the subsurface is therefore important in understanding how and where hydrocarbons are generated. having very high molecular weights. carbon dioxide. The amount of organic matter tied up in the form of kerogen in sediment is far greater than that in living organisms or in economically exploitable accumulations of coal. True kerogens. Oil shales. whether these hydrocarbons are mainly oil or gas. humic acids. when the chemical and biological destruction and transformation of organic tissues begin.
the subdued level of bacterial activity allows more time for the formation of geopolymers and. is developing a general method of describing gross kerogen composition and relating it to hydrocarbon-generative capacity. Subsequent investigations have identified Type IV kerogen as well. They identified three main types of kerogen (called Types I. are converted into saturated or cyclic structures. large amounts of sulfur may become incorporated into the kerogen structure. Kerogen formation competes with the destruction of organic matter by oxidative processes. Even if such a description were possible.18 reduction is occurring in the sediments. The four types of kerogen. Microorganisms prefer to attack small molecules that are biogenic. and their organic precursors Transformation of organic material in sediments and sedimentary rocks. and ultimately of much greater practical value. Geopolymers are more or less immune to bacterial degradation. and if the sediments are depleted in heavy-metal ions (which is often the case in nonclastic sediments but is seldom true in shales). In a low-oxygen (reducing) environment. One way that we can begin is by classifying kerogens into a few general types. Carboncarbon double bonds. it would not be of great and direct significance to exploration geologists.Kerogen . the macerals that they are composed of. The amount of sulfur contributed by the original organic matter itself is very small. KEROGEN COMPOSITION Because each kerogen molecule is unique. In an oxidizing environment many of the small biogenic molecules will be attacked by bacteria before they can form geopolymers. contain mainly the most resistant types of biogenic molecules that were ignored by microorganisms during diagenesis. or at least look very much like biogenic molecules. About a decade ago workers at the French Petroleum Institute developed a useful scheme for describing kerogens that is still the standard today. in contrast. . II. which are highly reactive. in contrast. it is somewhat fruitless to attempt a detailed discussion of the chemical composition of kerogens. therefore. and III) and have studied the chemical characteristics and the nature of the organisms from which all types of kerogens were derived. Those kerogens formed under oxidizing conditions. What is within our reach. because the bacterial enzyme systems do not know how to attack them. better organic preservation. Kerogens formed under reducing conditions will be composed of fragments of many kinds of biogenic molecules. Most organic oxidation in sedimentary environments is microbially mediated.
Most Type II kerogens are found in marine sediments deposited under reducing conditions. Type IV kerogens are highly oxidized and therefore contain large amounts of oxygen. Type III kerogens are composed of terrestrial organic material that is lacking in fatty or waxy components. Utah. in contrast. which mainly contain polycyclic aromatic systems. because they all have great capacities to generate liquid hydrocarbons. Type II (liptinitic) kerogens are also high in hydrogen. Type I (algal) kerogens have the highest hydrogen contents because they have few rings or aromatic structures. They are generally considered to have essentially no hydrocarbon-source potential. have the lowest hydrogen contents. have lower hydrogen contents because they contain extensive aromatic systems. Van Krevelen diagram showing maturation pathways for Types 1 to IV kerogens as traced by changes in atomic HIC and OIC ratios. unless they have small inclusions of Type II material. In the immature state. and Colorado. . Cellulose and lignin are major contributors. pollen and spores. are normally considered to generate mainly gas. Occurrences of Type I kerogens are limited to anoxic lakes and to a few unusual marine environments. The shaded areas approximately represent diagenesis. Type I kerogens have high generative capacities for liquid hydrocarbons. successively. Type I and Type II kerogens. Type III kerogens have high oxygen contents because they are formed from lignin. They also include contributions from bacterial-cell lipids. and fossil resin. and carbohydrates. catagenesis. Type II kerogens arise from several very different sources. Extensive interest in those oilshale deposits has led to many investigations of the Green River Shale kerogens and has given Type I kerogens much more publicity than their general geological importance warrants. Type IV kerogens contain mainly reworked organic debris and highly oxidized material of various origins.Kerogen . Heteroatom contents of kerogens also vary with kerogen type. contain far less oxygen because they were formed from oxygen-poor lipid materials. Type III (humic) kerogens. Type III kerogens have much lower hydrocarbon-generative capacities than do Type II kerogens and. The various Type II kerogens are grouped together. in contrast. leaf waxes. Type IV kerogens. Hydrogen contents of immature kerogens (expressed as atomic H/C ratios) correlate with kerogen type. cellulose. The best-known example is the Green River Shale. of middle Eocene age. and metagenesis. phenols. including marine algae. despite their very disparate origins. from Wyoming.19 Type I kerogen is quite rare because it is derived principally from lacustrine algae.
represents drygas generation." Metagenesis begins long before true rock metamorphism. they are to kerogen what minerals are to a rock. Although the terms catagenesis and oil generation are often used synonymously. nonclastic sediments). especially when we are discussing both aspects simultaneously. The correspondence is not perfect. Thermal decomposition reactions. they represent fundamentally different perspectives. Maceral names were developed by coal petrologists to describe. called maturation. proving the origin of the particle. In principle. whereas hydrocarbon generation focuses on the production of hydrocarbon molecules. In this text we shall use the terms somewhat interchangeably. however.Kerogen . metagenesis is not equivalent to "metamorphism. What appears to be vitrinite (Type III kerogen) by visual analysis may have chemical characteristics intermediate between Type II and Type III kerogens because of the presence of small amounts of resin or wax. . however. forcing us to make assumptions about the source organisms. because fresh waters are usually low in sulfate. Most high-nitrogen kerogens were therefore deposited under anoxic conditions where diagenesis was severely limited. Catagenesis and hydrocarbon generation occur concurrently. The kerogen in a given sedimentary rock includes many individual particles that are often derived from a variety of sources. In many cases the original cellular structure is still recognizable. Many high-sulfur kerogens are also high in nitrogen. By convention the term catagenesis usually refers to the stages of kerogen decomposition during which oil and wet gas are produced. called catagenesis and metagenesis. It is possible to make a reasonably good correlation between kerogen type based on chemical characteristics and kerogen type based on visual appearance. High-sulfur kerogens (and coals) are almost always associated with marine deposition. The different types of kerogen particles are called macerals. marine. Kerogen sulfur. break off small molecules and leave behind a more resistant kerogen residue. anoxic. which occurs after catagenesis. in some cases. because there is not a perfect biological separation of the various types of living organic matter. Thus few kerogens consist of a single maceral type. KEROGEN MATURATION INTRODUCTION Very important changes. a term taken trom coal petrology. Kerogen types are defined by the morphologies of the kerogen particles. which is destroyed rapidly during diagenesis. they are not precisely equivalent. Despite its name. Sulfur is only incorporated into kerogens in large quantities where sulfate reduction is extensive and where Fe +2 ions are absent (organic-rich. in contrast. Catagenesis refers to transformations of kerogen molecules. most terrestrially influenced kerogens are low in nitrogen. but they really represent different aspects of the same process.20 Sulfur and nitrogen contents of kerogens are also variable and. Microscopic organic analysis has reached a fairly high level of refinement and is often capable of assessing kerogen type with good accuracy. Metagenesis. In others the original fabric has disappeared completely. Macerals are essentially organic minerals. The division of kerogens into Types I-IV on the basis of chemical and hydrocarbon-generative characteristics has been supported by another independent scheme for classifying kerogens using transmitted-light microscopy. Because lignins and carbohydrates contain little nitrogen. is derived mainly from sulfate that was reduced by anaerobic bacteria. A list of the most common macerals and their precursors is given in the table presented earlier in this chapter. interrelated. the materials from which a maceral was derived. The small molecules eventually become petroleum and natural gas. Nitrogen is derived mainly from proteinaceous material. wherever possible. The biggest problem comes in identifying Type III kerogen. but it also continues through the metamorphic stage. occur when a kerogen is subjected to high temperatures over long periods of time.
in most cases decreases of temperature in excess of about 20°-30° C due to subsurface events or erosional removal will cause the rates of catagenesis to decrease so much that it becomes negligible for practical purposes.21 This chapter will focus on those changes in the residual kerogen that accompany catagenesis. the chemical process of maturation never stops completely. These reactions are intimately related to important changes in the chemical structure of kerogen. Thus the steady decrease in hydrogen content of a kerogen (usually measured as the atomic hydrogen/carbon ratio) during heating can be used as an indicator of both kerogen catagenesis and hydrocarbon generation. Some of these changes can be measured quantitatively. For practical purposes. simply because the longer time available compensates for lower temperatures. and III kerogens will therefore be very similar chemically. In the late stages of maturity. Furthermore. In contrast. as evidenced by low maturity. it is also true that other changes in kerogen properties have little or nothing to do with it. Types I. The more hydrogen a kerogen contains. thus allowing us to judge the extent to which kerogen maturation has proceeded. is to monitor hydrocarbon generation. including the Miocene Monterey Formation of southern California. There is a steady color progression yellow-goldenorange-light brown-dark brownblack as a result of polymerization and aromatization reactions. Because many of the light product molecules are rich in hydrogen. the residual kerogen gradually becomes more aromatic and hydrogen poor as catagenesis proceeds. after hydrogen loss is well advanced. provided that the hydrogen content of the kerogen was known prior to the onset of catagenesis. We shall look now at the various techniques for estimating the extent of hydrocarbon generation from kerogen properties and see how closely each of them is related to hydrocarbon generation. Nitrogen and sulfur are also lost from kerogens during catagenesis. the rates of catagenesis are generally not important at temperatures below about 70° C. Furthermore. high-sulfur oils found in a number of areas. Old rocks will often generate hydrocarbons at significantly lower temperatures than young rocks. As we saw earlier. The most important implication of these chemical changes is that the remaining hydrocarbongenerative capacity of a kerogen decreases during catagenesis and metagenesis. Nitrogen loss occurs primarily during late catagenesis or metagenesis. oil. however. even if drastic decreases in temperature occur. The real reason for following kerogen catagenesis. the more hydrocarbons it can yield during cracking. It is impossible to set precise and universal temperature limits for catagenesis.Kerogen . Kerogen maturation is not a reversible process-any more than baking a cake is reversible. and thus are not necessarily valid indicators of hydrocarbon generation. EFFECTS OF MATURATION ON KEROGENS Kerogen undergoes important and detectable changes during catagenesis and metagenesis. The composition of the products (bitumen. II. Although it is obvious that many measurable changes in kerogens are related to hydrocarbon generation. This complex interplay between the effects of time and temperature on maturity is discussed in a later chapter. and gas) will be discussed in a following chapter. possessing essentially no remaining hydrocarbon generative capacity. of course. much of the sulfur is lost in the earliest stages of catagenesis. the cracking of any organic molecule requires hydrogen. All kerogens become increasingly aromatic and depleted in hydrogen and oxygen during thermal maturation. Chemical reaction-rate theory requires that the rates of reactions decrease as temperature decreases. but it also states that at any temperature above absolute zero reactions will be occurring at some definable rate. Kerogen particles become darker during catagenesis and metagenesis. much as a cookie browns during baking. There is therefore no necessary cause-and-effect relationship . but they are not necessarily identical with hydrocarbon generation. because time also plays a role.
called vitrinite reflectance. while others are small heterocompounds. its structure becomes more ordered. small molecules are broken off the kerogen matrix.Kerogen .22 between kerogen darkening and hydrocarbon generation. Kerogens. resulting in lower bitumen contents in the source. As kerogen matures and becomes more aromatic. carbon-isotopic compositions of kerogens are affected little by maturation. These structural reorganizations bring about changes in physical properties of kerogens. has been widely and successfully applied in assessing kerogen maturity. the more an incident light beam will be scattered. One property that is strongly affected. and the less it will be reflected. Some of these are hydrocarbons. For example. These small compounds are much more mobile than the kerogen molecules and are the direct precursors of oil and gas. Half a century ago coal petrologists discovered that the percentage of light reflected by vitrinite particles could be correlated with coal rank measured by other methods. Because coal rank is merely a measure of coal maturity. Kerogens often fluoresce when irradiated. The more random a kerogen's structure. because the flat aromatic sheets can stack neatly. there would be a large and continuous build-up of bitumen in the rock as a result of catagenetic decomposition of kerogen. Except for darkening. the visual appearance of kerogen also does not change during catagenesis: kerogen types are generally recognizable until the particles become black and opaque. What actually occurs. the technique. contain large numbers of unpaired electrons. Cracking often produces free radicals. during metagenesis the chief product is methane. Both curves are highly . The difference between the two curves represents bitumen expelled from the rock or cracked to light hydrocarbons. If neither expulsion from the source rock nor cracking of bitumen occurred. and because vitrinite particles also occur in kerogens. Some properties of kerogen change very little during catagenesis. is that some of the bitumen is expelled from the source rock or cracked to gas. and no guarantee that a particular kerogen color always heralds the onset of oil generation. however. The concentration of free radicals in a given kerogen has been found to increase with increasing maturity. especially highly aromatic ones. Free-radical concentrations can be measured by electron-spin resonance. The intensity and wavelength of the fluorescente are functions of kerogen maturity. and which can be used to gauge the extent of molecular reorganization. Bitumen generation occurs mainly during catagenesis. somewhat beyond the oil-generation window. A general name tor these molecules is bitumen. HYDROCARBON GENERATION As kerogen catagenesis occurs. which are unpaired electrons not yet involved in chemical honds. Plot of bitumen generation as a function of maturity (dashed fine) compared to bitumen remaining in rock (solid line). is the ability of kerogen particles to reflect incident light coherently.
however. Rich rocks will become overpressured earlier than lean ones and thus will also expel hydrocarbons earlier. as measured by parameters such as vitrinite reflectance. In such cases the expelled products will be mainly gas. residual kerogen as well as small molecules that are the direct precursors for petroleum and natural gas.23 idealized. we cannot always define the limits of hydrocarbon generation with great confidence. those rocks that generate few hydrocarbons may not expel them until they have been cracked to gas. Catagenesis of kerogen produces a more aromatic. Resinite consists of polymerized terpanes (ten-carbon isoprenoids) that can decompose easily by reversing the polymerization process. but none of these measurements is closely linked to the actual process of hydrocarbon generation. Resinite and sulfur-rich kerogens are able to generate liquid hydrocarbons earlier than other kerogens because of the particular chemical reactions occurring in those two materials. Given the significant chemical differences among the various types of kerogens. Other kerogens usually follow a more traditional model. when large geopolymers are created from biological molecules. Numerous methods exist for tracing the history of a kerogen and determining its original chemical and physical characteristics. We shall consider the latter briefly here. High-sulfur kerogens generate heavy. high-sulfur oils at low levels of maturity. hydrogen-poor. Many workers now believe that microfracturing of source rocks is very important tor hydrocarbon expulsion. Conversely. whereas those kerogens that contain few lipids will generate mainly gas. The chemical composition and morphology of kerogen macerals depend both on the type of original organic matter and on diagenetic transformations. . including rock physics and organic-geochemical considerations. Effective generation of hydrocarbons requires that the generated products be expelled from the source-rock matrix and migrated to a trap.Kerogen . because natural variations among samples cause much scatter in experimental data. The chemical composition of a kerogen controls the timing of hydrocarbon generation and the type of products obtained. It has become apparent in recent years that not all kerogens generate hydrocarbons at the same catagenetic levels. Candidates for early expulsion would be very organic rich rocks and those containing resinite or high-sulfur kerogens. Timing and efficiency of expulsion depend on a number of factors. Sulfur-rich kerogens decompose easily because carbon-sulfur hbonds are weaker than any bonds in sulfur-poor kerogens. Several methods exist for estimating the extent to which hydrocarbon generation has occurred in a given kerogen. Thus. which in turn is partly attributed to hydrocarbon generation itself. Kerogens formed from resinite will generate condensates or light oils quite early. although we know that oil generation does occur during the phase we call catagenesis. this result is hardly surprising. Kerogens formed from lipid-rich organic material are likely to generate liquid hydrocarbons. SUMMARY Kerogen begins to form during early diagenesis. Source rocks that generate large amounts of hydrocarbons early are likely to expel those hydrocarbons early. In very lean rocks expulsion may occur so late that cracking of the generated bitumen is competitive with expulsion. Microfracturing is related to overpressuring.
000. are more commonly studied. branched hydrocarbons (including isoprenoids). The large sizes of asphaltene units render . The final fraction contains very large. Major compositional changes occur in going from bitumen to petroleum. However. many unanswered questions remain about the processes that transform bitumen into petroleum. have been studied in petroleums. and cyclics. Some of these are present in relatively large quantities. Bitumen and petroleum compositions can also be used as tools in correlating samples with each other. and steranes. Heavier aromatic and naphthenoaromatic hydrocarbons. Such correlations can be particularly useful in establishing genetic relationships among samples. In order to investigate the individual compounds present.24 Bitumen. but we are not certain whether they occur mainly within the source rock or during migration through the reservoir rock. and Natural Gas INTRODUCTION Petroleum obtained from reservoir rocks and bitumen extracted from fine-grained rocks have many similarities. while others are only trace contributors. contains a wide variety of small and medium-sized molecules with one or more heteroatoms. Each of the fractions contains certain types of chemical compounds. Light aromatic hydrocarbons. One fraction consists mainly of saturated hydrocarbons. however. like benzene and toluene. Petroleum. NSOs. Both bitumens and petroleums exhibit a wide range of compositions. A second fraction consists of aromatic hydrocarbons and some light sulfur-containing compounds. indeed. The lighter of these fractions. particularly those derived from diterpanes. Maturity also exerts control over bitumen and petroleum composition. Asphaltenes tend to aggregate into stacks because of their planarity. We also do not know how much of the change involves chemical reactions. Saturated hydrocarbons are the most thoroughly studied of the components of petroleum and bitumen because they are the easiest to work with analytically.Bitumen. triterpanes. Much of this variety is related to source-rock facies and the composition of the kerogens that generated the bitumens. Few of these heterocompounds have been studied carefully. but they also exhibit many important differences. n-alkanes. and how much is due to physical separation of chemical compounds having very different properties. The influence of the lithologies of source and reservoir rocks on these compositional changes is poorly understood. and Natural Gas - 5 . and form complexes with molecular weights of perhaps 50. bitumen is almost universally accepted as the direct precursor for petroleum. and resins. but these compounds are lost from bitumens during evaporation of the solvent used in extracting the bitumen from the rock. Reservoir transformations in some cases greatly affect oil composition and properties. Petroleum. we must separate the characteristics related to kerogen composition from those related to the transformation of bitumen to petroleum and from those related to changes occurring in reservoirs. In order to understand bitumen and petroleum compositions and to use them for exploration. highly aromatic asphaltene molecules that are often rich in heteroatoms. There is no doubt that they are related. we first separate a crude oil or a bitumen into several fractions having distinct properties. Most of the NSO compounds appear in the remaining two fractions. This chapter will compare and contrast bitumen and petroleum compositions and examine the factors responsible for the observed differences. variously called polars. COMPOUNDS PRESENT IN BITUMEN AND PETROLEUM GENERAL CLASSES OF COMPOUNDS Both bitumen and petroleum contain a very large number of different chemical compounds.
because the concentration of n-alkanes often decreases with increasing carbon number. CPI values can therefore . Many other types of organic compounds in crude oils and bitumens are not considered to be biomarkers because they cannot be related directly to biogenic precursors. or members of the n-alkane series. Asphaltenes can thus be removed from oils or bitumens in the laboratory or refinery by adding a light hydrocarbon. Sediments are also known that exhibit a strong preference for n-alkanes having an even number of carbon atoms. Petroleum. the CPI is greater than 1. These compounds. In most cases. The most useful biomarkers serve as indicators of the organisms from which the bitumen or petroleum was derived. asphaltene molecules have not been studied in detail. of biological origin. the lower-carbon homologs are given more weight in the calculation. Many sediments. an abbreviation for biological markers. Because of their molecular complexity and heterogeneity. 29. even-carbon homologs predominate as strongly as do the oddcarbon homologs among the n-alkanes. or CPI. whereas in other instances we may be able to limit the possible precursors to only a few species.0. These n-alkanes are believed to be formed by hydrogenation (reduction) of longchain fatty acids and alcohols having even numbers of carbon atoms. SPECIFIC COMPOUNDS Biomarkers.or even-carbon homologs is evident. depending upon the species present. but their sources are simply no longer recognizable due to diagenetic and catagenetic transformations. however.and even-carbon members is equal. However. and 31 atoms. although we know for certain that the biomarker molecule is biogenic. such as pentane or propane. They are. If odd-carbon homologs predominate. are essentially molecular fossils. Their n-alkane distributions reflect this mix. Other compounds. In a few cases specific precursor organisms or molecules can be identified. FACTORS AFFECTING COMPOSITION OF BITUMEN AND PETROLEUM SOURCE AND DIAGENESIS Biomarkers n-Alkanes were among the first biomarkers to be studied extensively.0. or of the diagenetic conditions under which the organic matter was buried. In contrast. 25. Carbon Preference Index. and by their catagenetic formation from long-chain compounds such as fatty acids and alcohols. marine algae produce n-alkanes that have a maximum in their distribution at C-17 or C22. receive contributions of n-alkanes from both terrestrial and marine sources. however. 27. Many of the compounds and classes of compounds that we find in crude oils and bitumens are called biomarkers. If the number of odd. and no preference for either odd. The average of two ranges is taken to minimize bias produced by the generally decreasing n-alkane concentrations with increasing number of carbon atoms. the CPI is 1. For the most part n-alkanes present in terrestrial plants have odd numbers of carbon atoms.25 them insoluble in light solvents. The distributions are quite sharp. (Among the acids and alcohols present in living organisms. we are unable to use it as an "index fossil" for specific organisms. of course. Their high concentration in bitumens and oils is best explained by their existence in plant and algal lipids. where input of terrestrial n-alkanes is minimal and diagenetic conditions are highly reducing. and Natural Gas .) Even-carbon preferences occur principally in evaporitic and carbonate sediments. Another important indication of the origin of n-alkanes is the distribution of individual homologs. which are derived from biogenic precursor molecules. was developed as a measure of the strength of the odd-carbon predominance in n-alkanes over the even alkanes (in the series from 23 upwards).Bitumen. especially 23.
Bitumen, Petroleum, and Natural Gas -
deviate from 1.0 even when no preference is distinguishable by visual inspection of the distribution curve. n-Alkane distributions are greatly modified by thermal maturity. Chain lengths gradually become shorter, and the original n-alkanes present in the immature sample are diluted with new n-alkanes generated during catagenesis. Because the newly generated n-alkanes show little or no preference for either odd- or even-carbon homologs, CPI values approach 1.0 as maturity increases. n-Alkane distributions in bitumens and oils derived from algae do not show the influences of maturity as clearly because the original CPI values are already very close to 1.0. It is therefore often difficult to estimate maturity levels in pelagic rocks on the basis of n-alkane data. Parameters other than Biomarkers. Sulfur contents are also strongly influenced by diagenetic conditions. For economic and environmental reasons, oils having more than about 0.5% sulfur are designated as high-sulfur. Many high-sulfur oils contain 1% sulfur or less, but in some areas sulfur contents can reach 7% (Monterey oils from the onshore Santa Maria area, southern California, for example). A few oils contain more than 10%. These high-sulfur bitumens and crude oils are derived from high-sulfur kerogens. As we saw earlier, sulfur is incorporated into kerogens formed in nonclastic sediments that accumulate where anaerobic sulfate reduction is important. Most oils and bitumens derived from lacustrine or ordinary clastic marine source rocks will be low in sulfur content, whereas those from euxinic or anoxic marine source rocks will be high-sulfur. Sulfur occurs predominantly in the heavy fractions of oils and bitumens, particularly in the asphaltenes. High-sulfur oils therefore have elevated asphaltene contents.
Introduction. There are two main types of reservoir transformations that can affect crude oils (reservoir transformations are not applicable to bitumen because, by definition, the material in a reservoir is petroleum). Thermal processes occurring in reservoirs include cracking and deasphalting. Nonthermal processes are water washing and biodegradation. Of these, cracking and biodegradation are by far the most important. Cracking and Deasphalting. Cracking, which breaks large molecules down into smaller ones, can convert a heavy, heteroatom-rich off into a lighter, sweeter one. Waxy oils become less waxy. API gravities increase, and pour points and viscosities decrease. When cracking is extreme, the products become condensate, wet gas, or dry gas. Cracking is a function of both time and temperature, as well as of the composition of the oil and the catalytic potential of the reservoir rock. It is therefore impossible to state that cracking always occurs at a certain depth or reservoir temperature. Most oils, however, will be reasonably stable at reservoir temperatures below about 90° C, regardless of the length of time they spend there. On the other hand, a reservoir above 120° C will contain normal oil only if the oil is a recent arrival. Although the role of catalysis in hydrocarbon cracking in reservoirs has not been proven, many workers suspect that clay minerals are important facilitators of hydrocarbon breakdown. Catalytic effectiveness varies greatly from one clay mineral to another, however, and our partial understanding of this difficult subject is not of much practical use at the present time. Cracking also brings about deasphalting, because asphaltene molecules become less soluble as the oil becomes lighter. Precipitation of asphaltenes in the reservoir will lower sulfur content and increase API gravity appreciably. Biodegradation and water washing. Water washing involves selective dissolution of the most soluble components of crude oils in waters that come in contact with the oils. The smallest hydrocarbon molecules and the light aromatics, such as benzene, are the most soluble. The effects of water washing are rather difficult to determine because they do not affect the oil fractions that
Bitumen, Petroleum, and Natural Gas - 27
are most frequently studied. Furthermore, in most cases the effects are quite small because of the low solubilities of all hydrocarbons in water. Finally, water washing and biodegradation often occur together, with the more dramatic effects of biodegradation obscuring those of water washing. Biodegradation is a transformation process of major importance. Under certain conditions some species of bacteria are able to destroy some of the compounds present in crude oil, using them as a source of energy. The bacteria responsible for biodegradation are probably a mixture of aerobic and anaerobic strains. Only aerobic bacteria are believed to actually attack hydrocarbons, but anaerobes may consume some of the partially oxidized byproducts of initial aerobic attack. Because biodegradation changes the physical properties of oils, it can have serious negative financial implications. Heavily biodegraded oils are often impossible to produce (Athabasca Tar Sands of Alberta, Canada, and the Orinoco heavy oils of Venezuela, for example). If production is physically possible, it may be expensive or uneconomic. It is therefore important to understand where and why biodegradation occurs, and what its effects are on oil composition. Biodegradation may actually start during oil migration (provided required temperature and oxygen conditions are met), because oil-water interactions are maximized then. Most biodegradation probably occurs within reservoirs, however, since the length of time an oil spends in a reservoir is usually much longer than its transit time during migration. Biodegradation can vary in intensity from very light to extremely heavy. Because the chemical and physical properties of an oil change dramatically in several predictable ways during biodegradation, biodegraded oils are easily recognized. Many basins have at least a few biodegraded oils, and in some areas they are epidemic. Bacteria that consume petroleum hydrocarbons have strong preferences. Hydrocarbons are not their very favorite foods, and they eat them only because there is nothing else available. The preferred hydrocarbons are n-alkanes, presumably because their straight-chain configurations allow the bacterial enzymes to work on them most efficiently. Also attractive to the "bugs" are long, alkyl side-chains attached to cyclic structures. After the n-alkanes and alkyl groups are consumed, the bacteria begin to destroy compounds having only a single methyl branch or those having widely spaced branches. Then they move on to morehighly branched compounds, such as the isoprenoids. In the last stages of biodegradation, polycyclic alkanes are attacked. Because the hierarchy of bacterial attack on crude oils is well known, it is possible to assess the degree of biodegradation by observing which compounds have been destroyed. Sulfur contents of crude oils also increase as a result of biodegradation. In a heavily biodegraded oil the sulfur content may increase by a factor of two or three. Sulfur is undoubtedly concentrated in the oil by selective removal of hydrocarbons, and may also be added by bacterially mediated sulfate reduction.
Although bitumens and crude oils contain the same compounds, the relative amounts are quite different. In the process of converting bitumen to petroleum, either the NSO compounds are lost in large quantities, or they are converted to hydrocarbons. In actuality, both processes probably occur, although selective loss of nonhydrocarbons during expulsion is probably most effective in concentrating the hydrocarbons. Bitumen composition depends strongly on the lithology of the host rock. Carbonates contain bitumens that are much richer in heterocompounds than are shales, and their hydrocarbon fractions are more aromatic. These differences are the result of the higher sulfur contents of kerogens in carbonates. Oils derived from carbonate sources are also richer in heterocompounds than oils sourced from shales.
Bitumen, Petroleum, and Natural Gas -
Natural gas contains many different compounds, although most of them are present only in trace quantities. The principal components with which we shall be concerned are light hydrocarbons (methane through butanes), C02, H2S, and N2. Carbon dioxide and N2 are generally associated with very hot reservoirs. C02 is derived either by oxidation of oil or gas or by decomposition of carbonates. The origin of the C02 can be determined easily by carbon-isotope measurements: the very different isotopic compositions of organic-carbon species and carbonates are carried over into any C02 derived from these materials. Nitrogen is thought to be an indicator of high levels of maturity formed primarily by metagenetic transformation of organic nitrogen and ammonia bound to clay minerals. Hydrogen sulfide is usually derived from high-sulfur kerogens or oils. These in turn are formed most readily in carbonates. Thus sour gas is most common in carbonate reservoirs or in places where the source rock was a carbonate. H2S could also be formed by the reaction of hydrocarbons with sulfate in reservoirs, especially carbonates containing anhydrite. Biogenic gas, most of which occurs at shallow depths, but which can apparently form (or at least persist) at depths of a few thousand meters, is very dry, containing only trace amounts of hydrocarbons heavier than methane. In contrast, the first gas produced during catagenesis is quite wet. With increasing maturity, gas again becomes progressively drier as a result of cracking of the heavier hydrocarbons to methane.
Bitumens and crude oils contain the same classes of compounds, but their relative concentrations are quite different. These differences are in some cases related to differences in maturity; in other examples they are probably a result of preferential expulsion of hydrocarbons from source rocks. Individual compounds occur in quite variable proportions in bitumens. Source, diagenesis, and maturity all exert control over these distributions. When source and diagenetic influences have been removed, the porphyrins, steranes, triterpanes, and n-alkanes in mature bitumens are found to be very similar to those in crude oils and quite different from those in immature bitumens. Oil compositions can also be strongly affected by reservoir transformations, including biodegradation, water washing, cracking, and deasphalting. Many of the factors that influence the composition of oils and bitumens are well understood and predictable, and can be used to obtain information about paleoecology, thermal history, and reservoir conditions. Gas composition is governed first of all by whether the gas is of biogenic or thermal origin. Biogenic gas is always dry, whereas thermal gas may be wet or dry. Carbon-isotope ratios are good indicators of the source of gas; biogenic gas is much lighter isotopically than thermal gases. Other important components, such as CO2, N2, and H2S, are indicative of high temperatures or sulfur-rich source material.
the microfractures heal. microfracturing occurs. There appear to be three distinct ways in which oilphase expulsion can occur. During intense hydrocarbon generation. and solution in gas. Laminated source rocks may therefore expel hydrocarbons with greater efficiency than massive rocks. Traps are the means by which migration is stopped and accumulation occurs. This chapter wi11 not go into the physics and chemistry of migration in detail. whereas accumulation of hydrocarbons requires concentration. particularly along lines of weakness such as bedding planes. Each of these steps is quite distinct from the others. PRIMARY MIGRATION MECHANISMS Many theories about primary migration (expulsion) have been popular at various times.Migration . . where pre-existing light hydrocarbons bleed out of the rocks prior to the onset of significant generation and expulsion. and pressure release can be repeated. Once the internal pressure has returned to normal. Its importance is probably limited to the edges of thick units or to thin source beds. When the internal pressures exceed the strength of the rock. Primary migration is the first phase of the migration process. oil-phase expulsion. Accumulation is the concentration of migrated hydrocarbons in a relatively immobile configuration. lowpermeability source rock into a carrier bed having much greater permeability. Momper's value has been widely accepted as a reasonable average. Secondary migration is the movement of oil and gas within this carrier bed. One occurs most commonly as a result of microfracturing induced by overpressuring during hydrocarbon generation. An important implication of the microfracturing model is that expulsion cannot take place until the strength of the source rock has been exceeded. Many cycles of pressure buildup. Momper (1978) suggested that in most cases no microfracturing or expulsion could occur until a threshold amount of bitumen had been generated in the source rock. Diffusion would therefore have to be coupled with a powerful concentrating force to yield accumulations of appreciable size. The hydrocarbons within the pores then become isolated again because of the impermeability of the waterwet source rocks to hydrocarbons. In order to understand the complex sequence of events that we call migration. The main problem with diffusion as an important mechanism of migration is that diffusion is by definition a dispersive force. Furthermore. any contribution by diffusion will be overwhelmed by that from other expulsion mechanisms. By far the most popular mechanism invoked today to explain primary migration is expulsion of hydrocarbons in a hydrophobic (oily) phase. Based on empirical evidence. but will describe the most widely held views on the dominant mechanisms of primary and secondary migration and accumulation. it involves expulsion of hydrocarbons from their fine-grained. expulsion. and overpressuring commences anew.29 6 . where they can be preserved over long periods of time. Although the exact threshold value must vary considerably as a function of rock lithology and other factors. Today there are only three mechanisms of primary migration that are given serious consideration by most petroleum geochemists: diffusion. but those that have been discounted will not be discussed here. we must look at each of these steps separately.Migration DEFINITIONS Migration is the movement of oil and gas within the subsurface. it is probably most effective in immature rocks. microfracturing. Diffusion has been shown to be active on at least a minor scale and over short distances in carefully studied cores.
This type of expulsion is probably only operative in very rich source rocks during the main phase of oil generation. Thus a source rock lying between two sands will expel hydrocarbons into both carrier beds. Sand stringers within shale units can provide secondary migration conduits for hydrocarbons sourced in the shales. particularly in brittle carbonate and opal-chert source rocks. this early expulsion mechanism seems to be limited to rocks having very high original contents of lipids. Such a phase could only exist where the amount of gas far exceeds the amount of liquid hydrocarbons. primary migration may be of poor efficiency. As soon as easier paths become available. requires that there be a separate gas phase. Massive. depending upon the carrier-bed characteristics of the surrounding rocks. unfractured source-rock units are relatively rare. oil-phase expulsion can take place when bitumen forms a continuous network that replaces water as the wetting agent in the source rock. Therefore the threshold must represent not only a hurdle to be cleared by the bitumen before it can leave the source rock. where they do exist. Because the source rock is overpressured. In most cases the distances of primary migration are probably between 10 centimetres and 100 m. most of the hydrocarbons are expelled. Fracture and joint systems. but it does give some idea of the efficiency of expulsion." We can only estimate the fraction of the bitumen left in the source rock during microfractureinduced expulsion. this approach is rather approximate. By comparing the average hydrocarbon compositions of bitumen and crude oil. expulsion of oil dissolved in gas.Migration . but a large proportion of NSO compounds and heavier hydrocarbons are left behind. Because neither case is of great general significance for petroleum formation. . therefore. Of course. Therefore. Because the driving force for microfracture-induced primary migration is pressure release. The organic matter expelled consists mainly of lipids that were present in the sediment during deposition and diagenesis.30 Once the threshold has been exceeded. but the mechanism by which overpressuring is achieved is not understood. upward. Primary migration is difficult and slow. the migrating fluids will take them. expulsion can be lateral. A second way in which oil-phase expulsion can occur is from very organic-rich rocks prior to the onset of strong hydrocarbon generation. Primary migration is unquestionably the most difficult part of the entire migration process. Finally. but also an "exit tax. Expulsion of hydrocarbons is facilitated because water-mineral and water-water interactions no longer need be overcome. we can estimate that once the expulsion threshold is reached the expulsion efficiency for bitumen is about 50%. or downward. hydrocarbons will be expelled in any direction that offers a lower pressure than that in the source rock. also make excellent secondary-migration pathways. The third mechanism. This expulsion process probably releases internal pressures in the rock. and assuming that expulsion of hydrocarbons is ten times as efficient as expulsion of NSO compounds. DISTANCE AND DIRECTION The distances traversed by hydrocarbons during primary migration are short. Thus inefficiency of expulsion is responsible for much of the difference in composition of bitumen and petroleum that we noted earlier. because petroleum is being forced through rocks having low matrix permeabilities. In most cases hydrocarbons are generated within short distances of viable secondary-migration conduits. it would be expected only in the late stages of catagenesis or in source rocks capable of generating mainly gas. Thus primary migration ends whenever a permeable conduit for secondary migration is reached. we conclude that solution in gas is a minor mechanism for oil expulsion.
Buoyancy promotes migration. Coalescence of globules of hydrocarbons after expulsion from the source rock therefore increases their ability to move upward through water-wet rocks. and becomes stuck until either the buoyant force or the capillary entry pressure changes. but it is not essential and does not change our basic model. In contrast. If the upward force of buoyancy is large enough. That is. we say that accumulation has occurred. The magnitude of the buoyant force is proportional both to the density difference between water and hydrocarbon phase and to the height of the oil stringer. the globule cannot enter. If. and therefore are more buoyant. Within massive sandstone. then the rate of hydrocarbon movement should be enhanced somewhat. Thus movement within a confined migration conduit will be updip perpendicular to structural contours whenever possible. whereas capillary-entry pressure retards or stops it. then the rate of hydrocarbon transport will be retarded. When hydrocarbons cease moving. subsequent movement of the hydrocarbons will be driven by buoyancy. Structural contours on the top of the carrier bed will . can modify hydrocarbon movement. secondary migration will cease until either the capillary-entry pressure is reduced or the buoyant force is increased. Retardatin of buoyant movement as an oil globule (X) is deformed to fit in to a narrow pore throat (Y). Where faulting or facies changes create impassable barriers (capillary-entry pressure exceeds buoyant force). The upward buoyant force is partly or completely opposed by the capillary-entry pressure. If the capillary-entry pressure exceeds the buoyant force. Hydrocarbons are thus capable of displacing water downward and moving upward themselves. the pore throat is very tiny or if the buoyant force is small. secondary migration will occur both laterally and vertically. Opposing the buoyancy is capillary-entry pressure. Whenever a pore throat narrower than the globule is encountered. If water is flowing in the subsurface in the same direction as hydrocarbons are moving by buoyancy. hydrocarbons entering the land from an underlying source rock will move toward the top of the sand even as they migrate laterally updip.Migration . if bulk water movement opposes the direction of buoyant movement. the more deformation is required. A third force-namely. the globule will squeeze into the pore throat and continue moving upward. the force required to deform the oil globule enough to enter the pore throat. Hydrocarbons are almost all less dense than formation waters.31 SECONDARY MIGRATION MECHANISM Once hydrocarbons are expelled from the source rock in a separate hydrocarbon phase into a secondary-migration conduit. This model is very simple. which is resistance to entry of the hydrocarbon globule or stringer into pore throats. hydrodynamic flow. requiring only the existence of two forces. however. DISTANCE AND DIRECTION Secondary migration occurs preferentially in the direction that offers the greatest buoyant advantage. This fact has important implications for tracing migration pathways through a thick conduit. migration may have to proceed at an oblique angle to structural contours. The smaller the pore throat. the globule must deform to squeeze into the pore. These modifications to the overall scheme are probably minor.
however. Stacked sands in a paleodelta. It is possible to have lateral migrations of as much as a few hundred kilometers in exceptional circumstances. Most basins. Vertical migration can also occur across formations. including the Athabasca Tar Sands of western Canada. leading to smaller fault-bounded accumulations and vertical migration. for example. by definition. thus providing a potentially very effective system for combined vertical and lateral migration. and the Saudi Arabian crude oils. Hydrocarbons had to remain in solution until they reached the trap. the process of hydrocarbon accumulation was somewhat mystical. Vertical migration distances can also be considerable. although it should be remembered that there are two fundamentally different types of vertical migration. ACCUMULATION INTRODUCTION In the old days.32 in general be more useful than contours on its base. Vertical migration across stratigraphic boundaries is more difficult. because final control on migration direction will be exerted by the upper part of the bed (assuming that no laterally continuous shale breaks divide the carrier bed into two or more separate systems). are basins in which lateral migration distances do not exceed a few tens of kilometers. not only because they often juxtapose carrier beds from different stratigraphic horizons.Migration . when migration was thought to occur mainly in water solution. Lack of long-distance migration opportunities implies that supergiant and giant accumulations are far less likely and that exploration targets will be smaller. Much more common. Drainage area is one of the most important factors influencing the size of hydrocarbon accumulations. Lateral migration is therefore often stymied. Nevertheless. at which time they suddenly became immiscible with the water and formed a separate hydrocarbon phase. are broken up tectonically and have poor lateral continuity of carrier beds. Indeed. the largest hydrocarbon deposits known. otherwise it is impossible to account for the incredible volumes of hydrocarbons in place today. as a result of both tectonic disruption and facies changes related to tectonic events. and has provided as carrier beds continuous blankets of sand juxtaposed with these source rocks. Cap rocks having low . the heavy oils in the Orinoco Belt of Venezuela. This model greatly simplifies the problem of accumulation. The problem in discussing long-distance migration is that such cases are rare. however. they are rare for very good geological reasons: they occur in extremely stable tectonic settings where major but gentle downwarping has deposited and matured huge volumes of source rocks. Unconformities also can juxtapose migration conduits. can offer possible pathways (although sometimes rather tortuous ones) for vertical migration. Long-distance migration implies. Faults may play an important role in vertical migration. all must have migrated long distances. There is no a priori reason why secondary migration cannot be a very-long-distance phenomenon. distances of several thousand feet are not unheard of. Migration updip within a single stratum can accomplish a large amount of "vertical" migration rather painlessly. The question of long-distance migration has been much discussed and disputed. Various mechanisms for exsolution were proposed to explain how all this was supposed to happen. but also because an active fault or the brecciated zone adjacent to a fault may itself have high permeability. because now accumulation can occur where the buoyancy-driven movement of the hydrocarbon phase is stopped or even strongly impeded. large drainage areas and chances for very large accumulations. Today we believe that hydrocarbons migrate as a separate phase. The absence of both tectonic and stratigraphic barriers permits long-distance migration. However.
and will be covered separately. Most hydrocarbon traps are either structural or stratigraphic. Lateral migration is of necessity short distance.Migration . Thus the Elmworth Field exhibits a water-over-gas contact. Fracturing associated with high races of oil generation in the Green River Shale has created a supergiant accumulation at Altamont. Because gas generation is very rapid. The simple principle behind a kinetic trap is that hydrocarbons are supplied to the trap faster than they can leak away. . CLASSICAL TRAPS. that strong hydrocarbon generation and migration is going on today. High rates of hydrocarbon generation can actually create traps by causing tensile failure of source rocks that have become overpressured as a result of hydrocarbon generation. and vertical migration becomes important. The low permeability sand thus creates a bottleneck to gas migration. Because the high permeability sand updip allows gas to migrate rapidly through. a fractured shale that is both source and reservoir. Seals in the traditional sense of the word may not exist. while the structure or lithologic change prevents lateral updip migration. Much of the hydrocarbon storage at Antelope is apparently in silts and sands juxtaposed with the producible Bakken reservoir. Gas generated in the late stages of kerogen catagenesis in the Alberta Deep Basin is trapped in a sandstone bed having lower permeability than the overlying sand. of course. The Elmworth Field in the Alberta Deep Basin of Canada is the prototype for kinetic gas accumulations. Gas production is actually from the low-permeability sand rather than from the high-permeability sand updip and downdip. This model requires. rocks whose capillary-entry pressures are high enough to overcome hydrocarbon buoyancy. No traditional seal exists. KINETIC TRAPS Kinetic traps represent a fundamentally new concept in trapping mechanisms for hydrocarbons.33 permeabilities to hydrocarbons provide barriers to migration: that is. Classical traps are well understood. Accumulations are small because drainage areas are small. The much smaller Antelope Field produces from the Mississippian Bakken Formation. Cross section across the Rhine Graben of West Germany showing the discontinuity of strata as a result of extensional tectonism endemic to rift basins. the low-permeability sands become filled with gas. it remains water wet. The seal prevents vertical migration from the reservoir rock into overlying strata.
tar-mat traps are worth discussing because they include the largest hydrocarbon accumulations known: those of the Athabasca Tar Sands and the Orinoco heavy-oil belt. and thus are not expelled as efficiently with the oil phase. and thus get left behind as the oil globule or stringer moves upward. because the same conditions that created the tar mat persist in the subsurface. unconsolidated sediments that would have no other means of retaining the methane. Cap-rocks in those fields are often poor. of course. Methane is by far the most commonly trapped gas molecule. Gas hydrates form and are stable under pressuretemperature regimes that occur at depths of a few hundred meters below the sea floor in deep water. Once expulsion has occurred. but hydrates large enough to accommodate butane molecules are known. the quantities of gas in such accumulations are huge. the lighter (gas) phase will be far more buoyant than the liquid phase. It will therefore migrate much faster and . large accumulations have formed despite high rates of leakage. and in zones of permafrost. Because intense oil generation is going on now. EFFECTS ON OIL AND GAS COMPOSITION It has already been suggested that most of the compositional changes seen between bitumens and normal crude oils occur during expulsion (primary migration) from the source rock. however. but it may also include some heavier hydrocarbons dissolved in the gas.34 Many of the accumulations in Pliocene reservoirs in southern California are also kinetic accumulations in a slightly different sense. because much of the methane trapped is biogenic and was formed in young. and would be incapable of sealing accumulations for long geologic periods. One important feature of methane hydrates is that they are much more efficient at storing methane than is liquid pore water. The technology necessary for producing these hydrocarbons has not yet been developed. Formation of hydrates thus provides an important trapping mechanism. In cases where no other structural or stratigraphic trapping mechanism exists. As soon as two immiscible phases are formed. GAS HYDRATES Formation of crystalline hydrates of natural gas provides an extremely efficient trapping mechanism for natural gas. Accumulations beneath tar-mat seals are generally biodegraded themselves. At the present time the vast potential of gas-hydrate accumulations is just beginning to be recognized. The polar (NSO) compounds interact most strongly with both mineral surfaces and water molecules. Despite the rarity of tar-mat seals. A second characteristic is that gas hydrates form effective seals against vertical hydrocarbon migration. When the original hydrocarbon phase contains large amounts of light components. Phase changes occur as a result of decreases in pressure and temperature during migration. These gas hydrates consist of a rigid lattice of water molecules that form a cage within which a single molecule of gas is trapped. these changes in temperature and pressure can cause separation of the original phase into a liquid phase and a gas phase. and the poor producibilitv of the hydrocarbons they trap. tar mats may provide the only possible means for retaining any hydrocarbons. TAR-MAT TRAPS Tar mats produced by biodegradation can create excellent seals. Because hydrate zones are often hundreds of meters thick. The polar molecules once again interact most strongly with interstitial water and mineral surfaces. there may be a chromatographic effect during secondary migration. contain mainly light components. especially methane.Migration . but in the future gas-hydrate accumulations may be of great economic significance. The gas phase will. The base of the gas hydrate zone forms a pronounced seismic reflector that often simulates bottom contours and cuts across bedding planes.
we want to determine the main pathways and conduite through which migration occurs. Polar compounds interact more strongly with water and rock minerals and thus move more slowly than hydrocarbons. as we have seen. Proximity to effective source rocks and their permeabilities to hydrocarbons determine conduits. are determined by structural contours on the top of the carrier beds. Efficiency of expulsion of liquids has already been estimated to be in the neighbourhood of 50% after the expulsion threshold has been reached. . Efficiency of expulsion for hydrocarbons is apparently much higher than for NSO compounds. Many light oils (often called condensates) probably have such an origin Proposed separation of petroleum components during secondary migration as a result of chromatographic effects.Migration . Timing of expulsion must be dealt with in a different way. both new phases will have compositions that differ drastically from the original phase. the efficiency of expulsion. as explorationists we have very pragmatic interests in migration. and the vertical and horizontal distances involved. Thus if we can determine the timing of generation. We already know two important facts about timing from our previous discussion: expulsion based on microfracturing cannot occur before generation. and the timing of expulsion. Pathways. We need to know when hydrocarbons moved. vertical faulting. and expulsion occurs concurrently with generation to relieve generation-induced overpressuring. Barriers can be created by folding. Tectonically stable basins have the best potential for long-distance migration and supergiant accumulations. in what direction they moved. In summary. SIGNIFICANCE FOR EXPLORATION Explorationists who are reading about migration will surely ask. We have already stated that oil is expelled primarily as a liquid phase. "What does this mean for exploration?" From their perspective the important aspects of primary migration are the nature of the hydrocarbons expelled (oil or gas). the barriers that modify die direction of migration and eventually stop it. and how far they moved. or by the presence of tars. depending upon stacking of reservoirs. by decreases in permeability as a result of facies changes. gas is presumably expelled as a gas phase.35 will also assume the structurally high position in any reservoirs containing both phases. leading to an enrichment of hydrocarbons in the expelled liquid. In using our understanding of secondary migration for exploration. and the possibilities of combined vertical and lateral migration. Unstable basins seldom have depositional or tectonic continuities necessary for longdistance lateral migration to occur. by faulting. Vertical-migration distances can be considerable. When separation of a single hydrocarbon phase into two phases occurs. we will also have determined the timing of expulsion. Lateralmigration distances are strongly influenced by tectonic and depositional histories of basins.
First. is known as the crest of the trap. we need a few definitions. by displacing the water already there in the porosity. The highest point of the reservoir. where it is lost. Faults will be marked by jumps of the contours. which may give a misleading impression of `lakes' of petroleum under the ground! Structure contour maps.(2-18) Before we go further. This may be caused either by the reservoir itself dying out or by an interruption of its upwards continuity to the surface. one or more cross-sections may be drawn. To complement the structure contour map. Note that we commonly highlight petroleum accumulations by shading or colouring the reservoir formations where they contain oil or gas. not only must the reservoir be overlain by an impervious layer forming a cap rock or seal (shales or evaporites are likely to be the most effective). Indeed. and furthermore we can map out the extent and shape of the trap with a good deal of precision-thanks mostly to modern seismic techniques. the ticks are on the downthrown sides of the faults. The location of a trap in the subsurface is often the first objective of an exploration program. it will escape to surface as a seepage. If then we are to find any of it still preserved. they should properly be drawn with the same scale for both the vertical and the horizontal. (b) A representation of the Piper field in the North Sea: the heavy lines are faults cutting the top of the reservoir and causing the contours to jump. up towards the ground surface. drilling a well into it. except that the contours are in depth below sealevel. which may refer either to its depth or to the spot under the ground where it lies. Nowadays we can do better.Petroleum Traps We have seen petroleum generated in and expelled from the source rock formation into an overlying or underlying reservoir. A structure contour map resembles an ordinary topographic contour map. Any oil getting there will be unable to migrate further and so it starts to accumulate. is the spill-point: this is where oil. so that the highest points on the map have the lowest values. before we reached our modern understanding of the geology of petroleum. THE REPRESENTATION OF TRAPS Traps are commonly depicted in two ways. (a) A simple hypothetical anticline.Petroleum Traps . If it can.36 7 . The lowest point. if more continues to migrate up into the trap than can be . Such a configuration of the reservoir is known as a trap. exploration used to consist largely of finding a trap. as the beds on one side are dropped down relative to the other. they can be mapped by means of contours drawn on the top of the reservoir formation. but it is often convenient to exaggerate the vertical to show the individual beds more clearly. but there must also be some sort of blockage to prevent further migration. is mapped by contours showing depth below sealevel. and hoping for the best. These are illustrated using a simple anticline as an example. The top of a reservoir formation. To give a true representation. The contours are in feet below mean sea-level.
the informal term pay is often used. formed partly by structural and partly by stratigraphic effects. in which the trap is formed by changes in the nature of the rocks themselves. which are rare and are mentioned mainly for completeness. Let us remember.e. 2. The trap is due to water flowing through the reservoir and holding the oil in places where it would not otherwise be trapped. the only structural effect being a tilt to allow the oil to migrate through the reservoir. They are normally classified under four headings (2-21): 1. so that we can recognize a generally horizontal oil-water contact. will occur as a gas cap above a gas-oil contact. Structural. which have porosities and permeabilities too low for them to contribute oil to production. separates out on top within the pore-spaces of the reservoir. petroleum migrating up along a reservoir can go no further and it accumulates there as a pool. 3. The vertical height between the spill-point and the crest is referred to as the closure. they are embraced by the familiar terms oilfield or gasfield. Combination traps. Oil being lighter than water. there are various types of . These have to be discounted and the bits that remain as useful reservoir in a well section may be lumped together as the net reservoir with a net pay. Stratigraphic. A single accumulation of oil or gas is called a pool. then we may see a gas-water contact.(or gas-) column. Where there is more than one such pool in the same or overlapping areas. Just a couple more terms. perhaps if more than one reservoir is present.37 accommodated. either by folding or faulting. Hydrodynamic traps. 4. that most reservoir formations include some tight intervals. Similarly gas. however. but not entirely due to either. where the trap has been produced by deformation of the beds after they were deposited. The vertical height of the oil (or gas) between the crest of the trap and the water contact is the oil. i. When referring to a single well. STRUCTURAL TRAPS The best known type of trap is the anticline: on reaching the crest. and the same term is used loosely to refer to the area of the trap above the level of the spill-point. Some terms used to define a trap. being lighter still. will spill out (under) and migrate on. Now we can start to consider the types of trap whose discovery may await us. However. If there is no oil. using a cross-section of a simple anticline as example (2-19). or in their layering.Petroleum Traps .
but an understanding of the shape and size of a prospect is clearly critical to programming an exploration well. maintains its shape constant down to depth. These compressive structures pose one problem right from the start. and we may be able to continue exploration down to depths where we have to stop for other reasons. Below this point we have just too much rock to fit into the anticline. Let us see what the implications are for exploration. Imagine an old-fashioned stone hot-water bottle in a bed with a blanket over it: we can still see the form of the hot-water bottle. so that the beds maintain a constant thickness throughout. and the blanket bulges upwards with an anticlinal shape. Cross-sections of trap-forming anticlines. beyond which there may be no trap left to explore as the consequence of decoupling of layers. then the position of the crest will shift with increasing depth. many structures have forms in-between the two extremes. Seismic may help. Compressive structures have a range of shapes between the purely concentric or parallel anticline and the similar fold. (a) The dips are the same on both flanks and the crest is beneath the same locality at all depths. and we may no longer be able to see where the bottle is. The similar anticline. The general principles of this are straightforward. so that the beds become intensely crushed and thrust together: we may no longer even have an anticline at all. There is a definite limit to the depths to which we should drill. Cover it with a few more blankets and a duvet or two. We will describe in a little detail the most important types of anticline. In this case. . noting the differences in shape and prospectivity that we have to try to interpret. These conditions mean that the anticline becomes smaller and tighter at deeper levels until we reach a common `centre of curvature'. in cross-section. we can find the trap present at all levels down to the basement. depending on the nature and strength of the rock layers being folded. the anticline is asymmetrical. but we commonly have to undertake some form of geometrical construction to interpret what is happening at depth. In this type of structure. a well would have to be located off-crest at surface. If. Anticlines.38 anticlines with different shapes and geometries that can affect both their prospectivity and the positions of optimum drilling locations: we have to try to understand them.Petroleum Traps . Other types of anticline can be formed without any lateral compression at all: an important one is the drape or drape-compaction structure. This leads us into the next problem. Traps can also be formed against faults if a chopped-off reservoir is thrown against a shale or other impervious rock. In practice. we have to know its depth to know where best to locate the well. on the other hand. (b) The anticline is asymmetrical and the crest shifts with increasing depth. we can thus expect to find only smaller and smaller accumulations of petroleum down to the centre of curvature. This is a very different kettle of fish from the concentric anticline. with one flank steeper than the other. therefore in order to drill into a reservoir near its highest point (where we would expect the oil to be). To test the crest at depth.(2-22) In the concentric fold the tops and bottoms of all the layers remain strictly parallel to each other. This can only happen if there is an apparent thickening of some beds over the crest of the fold.
the beds being draped over an upfaulted block (horst) of basement rocks. Diagrammatic section through two salt plugs. The last type of anticline that we should be aware of is the roll-over anticline. This creates a rollover anticline. showing the variety of traps that may be associated with them. it is not always easy to separate out the two effects. a salt pillow or a salt dome. but also . if the first sediments in a basin were deposited over a hilly surface. and finally a residual bulge may be left between two nearby plugs: a turtle or turtle-back structure.39 A drape-compaction anticline. bending downwards into the hole. however. and then to burst through them in the form of a salt plug or salt wall. Not only may an anticline be pushed up over the plug. Note a characteristic of these anticlines: not only do they `grow' with depth. which contains more than four times as much oil as the whole of the North Sea put together. higher beds will gradually mute and suppress the structure until it is no longer present at shallow levels. the Middle East. is in one such trap. and several others. Ghawar in Saudi Arabia. Nature. Extensive salt deposits and plugs with associated traps occur in many parts of the world: the southern North Sea and northern Germany. the Canadian Arctic Islands. Another is the Forties field in the North Sea.(2-26) A wide variety of traps can be associated with salt plugs. so that it is steep near the surface and flattens with depth. the Gulf Coast of the USA. Note also that salt. In effect the downthrown side is being pulled away from the upthrown side which would tend to create an open fissure along the fault. note that the largest oilfield in the world. it may bend up and seal off the strata it cuts through. can be a perfect seal to any underlying accumulations. Note that the anticline dies out upwards towards the surface. All of these possible traps may contain hydrocarbons. it may extend up to the surface of the ground or only part way if the supply of salt is limited. This occurs alongside a normal fault that is curved.(2-25) Similarly. In case anyone should think that this is unimportant. then they will blanket the hill as an anticline. A second effect comes into play here: because there is a greater thickness of beds off the structure than over the top.Petroleum Traps . it is also liable to fracture the overlying and surrounding beds creating fault traps. This compaction enhances the anticline formed by the drape. does not like empty holes. those near the bottom of the sequence are going to be squeezed and compacted more on the flanks than on top of the feature as it gets buried. much of the west coast and continental shelf of Africa. where the beds are draped over the eroded stumps of an old Jurassic volcano. and the beds on the downthrown side above the curving fault collapse to fill the gap. The effect of salt diapirism will be initially to bulge up the overlying sediments as an anticline. and hence the combined name. or over an upfaulted block or horst. being plastic.
or slumping as a sort of land-slide. The reader may care to think through the various situations sketched as bits of cross-sections in the following figure in which the faults themselves are non-sealing. Again. and its depth. a fault can provide a seal. down towards the deep ocean. Much of the oil under the Niger and Mississippi Deltas is in such roll-over anticlines. we still do not fully understand what the difference is due to. We know that sometimes. thus causing sand against sand to permit migration and sand against shale to be sealing. It adds further uncertainties to our predictions of the subsurface occurrence of oil and gas. All very puzzling! Although attempts have been made to investigate the problem in Nigeria and elsewhere. therefore. in both ways. Kim+P. T. and in understanding them. L. Upper Cretaceous. Cross-section through the Wytch Farm oilfield. we have to know whereabouts in the succession our prospective reservoir lies. setting it against something impermeable. UK. whether or not the reservoir is completely or only partially offset. these predated the deposition of the Upper Cretaceous. but we also know that sometimes faults are pathways for migrating petroleum and non-sealing at all. The oil is in two reservoirs. BS+MJ+O. Triassic. as at Wytch Farm. although there are many problems in trying to locate them in the subsurface. Roll-over anticlines: (A) a simple roll-over into a normal fault. Tr. The proviso is that we also have lateral closure: this may be provided by further faulting. (2-28) We do not propose to discuss fault traps in detail. in both cases. Occasionally indeed. Fault traps We indicated above that a trap may be formed where a dipping reservoir is cut off up-dip by a fault. and how big it is. It also depends on whether the fault itself is sealing or non-sealing.. southern England. to locate an exploration well in the right place. . Lower Cretaceous. (B) a roll-over complicated by subsidiary faulting near the crest. will depend on the dip of the reservoir as compared with that of the fault. The sealing capacity of faults is a major difficulty confronting us. (2-27) These roll-over structures are particularly important where the `stretching' is caused by a very thick pile of sediments at the edge of a continent gently slipping. The large Wytch Farm oilfield of southern England offers a splendid example. and naturally we have some ideas on the subject. the position of the crest is displaced with depth and that accumulations in successive reservoirs will not underlie the same surface position. trapped against faults to the south. whether the fault is normal or reverse.Petroleum Traps . Note that. Tertiary. at deeper levels the crest will shift away from the position of the fault at surface. Lower Jurassic. Middle Jurassic. and it will depend on the amount of displacement on the fault. W. it seems that one and the same fault may act. or have acted in the past. Whether or not there is a trap.40 they are asymmetrical. Upper Jurassic. or by opposing dips.
A sand deposited in a river channel will be confined by the banks and. no structural control is needed. and on the amount of displacement of the reservoir. strongly weathered basement rock (granites.Petroleum Traps . the porosity could be preserved beneath the unconformity. More esoterically.(2-29) STRATIGRAPHIC TRAPS Petroleum may be trapped where the reservoir itself is cut off up-dip. A dipping reservoir. In fact. they differ somewhat in principle from the others. is the biggest in the USA outside Alaska. we have an isolated trapping situation. cut across by erosion and later covered above the unconformity by impermeable sediments. say. until perhaps the supply of sand runs out. may serve as an isolated stratigraphic trap. gneisses) under an unconformity serve as reservoirs in China and North Africa. fan sands provide one of the prime present-day exploration . A lot of oil has been found in recent years in this sort of trap in the North Sea. however. but are generally classified as stratigraphic traps. to provide a trap when later covered with. Non-unconformity traps are even more diverse. and leave the reader to speculate on other possibilities. the beach sands will spread progressively over the land surface. It would be pointless to list all of the possible types of stratigraphic trap that can exist. so we will mention a few to convey the general idea. claystone. if terminated updip as not infrequently happens. In this manner. Consider the sea gradually encroaching over the land as sea level rises. let us note that a number of traps. It is presumed that petroleum cannot escape up the fault plane. some of them very important. We mention just three examples. will spread out as a fan over the ocean floor. The variety in size and shape of such traps is enormous. depending on whether the fault is normal or reverse. possibly through a submarine canyon. for example. A coral reef overwhelmed by muds. Unconformity traps can also be found above the break. a hill on the old land surface may be formed of permeable rock.41 Six trapping and two non-trapping configurations against a fault. becoming younger as time goes on. on the direction of dip of the beds relative to the fault plane. A flood of sand washed off the shallow continental shelf into the deeper ocean. First. but nevertheless known. to a large extent reflecting the restricted environments in which the reservoir rocks were deposited. if drowned by shales. We would be left with a sandstone reservoir dying out above the unconformity. provides the classic case: the East Texas field. thus preventing further migration. its edges will provide an example of a reservoir dying out laterally. are formed by unconformities.
As the more easily found structural traps are running out in much of the world. possibly even before it . An investigation into the sealing qualities of faults affecting roll-over anticlines in the Niger Delta. where there is enough of it in the section.(2-31) The oil in the Argyll and many other fields in the North Sea is trapped in tilted and faulted Permian to Jurassic reservoirs. and truncated by erosion. it is presumed that the fault is non-sealing. The oil in these fields can only have migrated there after the traps were sealed by the higher sequences. This vital factor. Again the range of possibilities is almost infinite. or the oil would have been lost. has most of its oil and gas trapped in a Carboniferous to Jurassic sequence which includes more than one reservoir. A block representation of the trap at the Prudhoe Bay field in northern Alaska. where the reservoirs overlie overpressured shales. Where a reservoir is full to spillpoint against a fault. The oil is held in the reservoirs by younger shales overlying the erosion surface (Fig. The reservoir beds were folded into an anticline. the biggest field in the USA.).(230) COMBINATION TRAPS A number of fields. neither completely controls the trap. tilted westwards. elsewhere it appears to form a trap. We may note here one most important consideration. there always seems to be something new as a challenge. Both the faulting and the unconformity control the traps. these beds were folded into a faulted east-west anticline. that the trap must be shown to have been there before the oil migrated. as the fault moved. The difference is believed to be due to clay being smeared into the fault plane.42 targets.Petroleum Traps . although such prospects are not easy to locate and may require a lot of sophisticated seismic. A couple of examples may give the idea. and where an oil-water contact is continuous across a fault. occur in traps formed by a combination of structural and stratigraphic circumstances. some of them large. The Prudhoe Bay field in northern Alaska. which were eroded and unconformably overlain by Cretaceous shales. This combination trap is partly structural (the anticline) and partly stratigraphic (beneath the unconformity). which was tilted west and eroded before deposition of the overlying beds now dipping east.
It is therefore always important to get a handle on the hydrodynamic regime in a reservoir for both exploration and oilfield development purposes. In this sort of situation.Petroleum Traps . of course. from our present-day point of view. are the more obscure and generally smaller prospects. it may find itself caught against an unevenness of the reservoir surface where there is no conventional trap at all. Such tilted contacts. in say ordinary anticlinal traps. entering a reservoir formation. We would recognize this from residual traces of oil in a water-bearing reservoir. . they are known in a number of parts of the world. up in the hills and percolating downwards towards a spring. Depending on the balance of forces acting on the oil. are not all that rare. The oil-water contact in such a hydrodynamic trap is normally tilted in the direction of water flow. or aquifer. a regime of water flow cannot normally be expected to remain constant for long. The trouble. but the oil reserves they contain show clearly that generally they are also bigger. is held against an unevenness of its upper surface by water flowing in the opposite direction. only for as long as the water keeps coming: dry up the supply of water. geologically speaking. therefore. Oil has found its way into the reservoir and is battling to migrate upwards to the surface against the flow of water. What our efforts are increasingly directed towards. Note that the oil-water contact is tilted down in the direction of water flow. traps in both number and size. as we do not want to waste the money drilling wells that would miss the oil altogether. Furthermore. attempting to escape to surface up a reservoir. This is what has been described as a hydrodynamic trap. A hydrodynamic trap. and the oil will be free to move again. The number of structural field of this size may partly reflect the fact that structural traps are easier to find than the others. cases are known where flowing water has apparently been able totally to flush oil out of an anticlinal trap. It is totally dependent on the flow of water and is effective. is that in most parts of the world the larger anticlines have now been drilled. perhaps from rain.(2-32) THE RELATIVE IMPORTANCE OF TRAPS A review of 200 giant oilfields (those containing 500 million barrels or more) emphasize the importance of structural. The timing of trap formation versus oil migration has not always worked out favorably. is yet another aspect of the petroleum geology that we have to assess in proposing exploration drilling. we would have to be careful where we locate and drill our oil production wells.43 was generated. essentially anticlinal. HYDRODYNAMIC TRAPS Imagine surface water. Oil. This may be one of the reasons why oil accumulations trapped hydrodynamically are rare. There is no structural or stratigraphic closure. indicating the former presence of an oil accumulation now lost.
45 EXERCISES EXERCISE 1: The following well logs have been hung on a structural datum.Make the interpretations from easy (A) to more difficult. The logs show SP (Self Potential or Spontaneous Potential) on the left and R (Resistivity) on the right. multi-interpretable (D). Interpret the geological relationships shown in each by drawing a structural cross-section through the logs.Petroleum Traps . .
Use this information to construct a northeastsouthwest structural cross section from the Richards well to the Dibble well. The Onondaga forms a thick biohermal reef over part of the field.. Wyckoff Reef Gas Field WellElevation CORNELL DIBBLE GUILD CHASE BANKS RICHARDS 2257' 2098' 2037' 2206' 2182' 2066' . N. A deep-seated downto-the-southwest fault extends upward along the southwest flank of the reef. located in Steuben County.46 EXERCISE PetroleumTraps 2 The Wyckoff Gas Field.Y. Elevations and marked logs are provided for 6 wells in the Wyckoff Field. Oriskany production is from a small anticline on the upthrown side of the fault. produces from Onondaga Limestone and/or Oriskany Sandstone.Petroleum Traps . Only the porous core facies is productive in the reef section (see map on next page). showing the interval from top of Onondaga to bottom of Oriskany.
Petroleum Traps .47 .
Petroleum Traps .48 .
much smaller amounts can be analyzed. This simple. the following distinctions can be made: Effective source rock: any sedimentary rock that has already generated and expelled hydrocarbons. the remaining source capacity and not the original capacity (Go). The term "effective source rock" obviously encompasses a wide range of generative histories from earliest maturity to overmaturity. The quantity actually measured in the laboratory is always G. For example. Go can only be measured directly for immature source rocks. This quantity. Analysis normally requires about one gram of rock. instead it must be estimated by measuring G for a similar sample that is still immature. MATURITY OF ORGANIC MATERIAL Knowing a rock's remaining source capacity G solves only one part of the puzzle. It follows from these definitions that a particular stratum could be an effective source rock in one place. a possible source rock in a nearby unstudied region. but if the rocks contain abundant organic matter. we cannot measure G directly for a sample that has already begun to generate hydrocarbons. For better communication. quick. Go.Source Rock Evaluation . Potential source rock: any immature sedimentary rock known to be capable of generating and expelling hydrocarbons if its level of thermal maturity were higher. is most meaningful if we can compare it to the rock's original source capacity. or is it because the rock is "burned out" (i. When we analyze a rock sample in the laboratory.. where G and Go are identical. PRINCIPLES OF SOURCE-ROCK EVALUATION QUANTITY OF ORGANIC MATERIAL The amount of organic material present in sedimentary rocks is almost always measured as the total-organic carbon (TOC) content. Although the term source rock is frequently used generically to describe fine-grained sedimentary rocks. overmature. the Phosphoria Formation of Wyoming and Idaho belongs to each of these classifications in different areas. is it because the rock never had a high initial source capacity. and might have no source potential at all in a fourth area where important facies changes had resulted in a drastically lower content of organic matter. Possible source rock: any sedimentary rock whose source potential has not yet been evaluated. we actually measure its remaining (or untapped) source capacity at the present day.Source-Rock Evaluation DEFINITION OF SOURCE ROCK Much of modern petroleum geochemistry depends upon accurate assessment of the hydrocarbonsource capabilities of sedimentary rocks. but which may have generated and expelled hydrocarbons. a potential source rock in a less-mature area. and inexpensive analysis serves as the first and most important screening technique in source-rock analysis. For example.49 8 .e. if G is very low. it is also necessary to know what level of thermal maturity is represented by that particular G value. However. that usage is a bit too broad and loose. in which case virtually all the initial . which we can call G. The difference between Go and G represents the hydrocarbons already generated in the effective source rock.
A substantial number of techniques for measuring or estimating kerogen maturity have been developed over the years. and then embedding the kerogen particles in an epoxy plug. In other rocks. TAI measurements are carried out on bisaccate pollen grains whenever possible. Such histograms are quite often difficult or impossible to interpret. All the methods have strengths and weaknesses. Vitrinite reflectance (Ro). paucity of first-cycle vitrinite renders vitrinite-reflectance measurements essentially worthless. After the plug is polished. Other macerals or solidified bitumens can often be misidentified as vitrinite. its maturity is not related to that of the rock in which it is found. from amorphous kerogen. and none can be applied in all cases. in which the vitrinite maceral is usually very common. in fact. vitrinite reflectance. in some cases it is essential. more common are histograms showing few vitrinite particles or multiple modes as a result of first-cycle vitrinite contaminated with reworked vitrinite or caving of less-mature material from up-hole. In order to minimize differences in color caused by changes in the type or thickness of the kerogen particles. Results are reported as Ro values.50 hydrocarbon-source capacity has already been used up)? The exploration implications of these two scenarios are. very different. the plot is a straight line. in obtaining more than one maturity parameter. with lower confidence. unless surrounding samples help us determine the indigenous vitrinite population. Reworked vitrinite is. The key to using maturity parameters effectively lies in evaluating the measured data carefully (and sometimes with skepticism) and. Because what is present is often reworked.Source Rock Evaluation . Despite its weaknesses. misidentification of macerals can cause problems. Thermal Alteration Index (TAI). Less commonly used are fluorescence and conodont color (CAI). the microscopist shines light on an individual vitrinite particle. along with a statistical analysis of the data. There are many problems with vitrinite reflectance as applied to kerogens. If a log scale is used for the reflectance. where the o indicates that the measurements were made with the plug immersed in oil. and pyrolysis temperature. The darkening of kerogen particles with increasing thermal maturity can be used as an indicator of maturity. All the techniques discussed are useful and probably reasonably accurate if the analytical work is carefully done. The feeling of most workers today is that there is no single maturity indicator that tells the whole story unerringly all the rime. The fraction of the incident beam that is reflected coherently is measured and recorded and stored automatically on a computer. or TAI). At the end of the analysis a histogram of the collected data is printed. Reflectance values are normally plotted versus depth in a well. The most commonly used maturity parameters today are spore color (Thermal Alteration Index. Because each maceral type increases in reflectance in a slightly different way as thermal stress increases. Vitrinite-reflectance measurements begin by isolating the kerogen with HCl and HF. the reflectance value of vitrinite increases. between 50 and 100 measurements will be taken. however. Vitrinite-reflectance techniques were developed for measuring the rank of coals. whenever possible. In many rocks vitrinite is rare or absent. In all cases it is worthwhile to supplement vitrinite with other measures of maturity. TAI values are estimated. In many areas it is easy to use and valuable. leading to frequent difficulties in establishing which vitrinite population is indigenous. TAI measurements are made on the same slides prepared for microscopic kerogen-type analysis. A few of these parameters will briefly be discussed. of course. The method is based on the fact that with increasing thermal stress. If enough vitrinite particles can be found. far more common in shales than in coals. even for experienced workers. vitrinite reflectance is the most popular technique today for estimating kerogen maturity. . If no pollen can be found. The ideal histogram of reflectance values is therefore rather rare.
51 Each laboratory has reference slides so that microscopists can continually compare the color determinations they are now making with those they and their colleagues made in the past. A careful worker can reproduce earlier work with excellent precision. or most commonly. Conodonts are isolated. Although TAI determinations are subjective. Conodonts are not very sensitive indicators of maturity within the oil generation window. TAI measurements are therefore often quite accurate and correlate very well with results from other techniques. thus defusing to a large degree the criticism that TAI is too subjective to be valid. TAI values estimated from amorphous material are always suspect and should be corroborated by other analyses. by removing the mineral matrix with acetic or formic acid. Early investigations showed that immature rocks often had high CPI . and thus helps expand the range over which maturities can be measured. lack of proper standardization. changes in conodont color are apparently due to carbonization of inclusions of small amounts of organic matter during catagenesis and metagenesis. One advantage of CAI over other maturity parameters is that because conodonts existed as early as the Cambrian. and thus are of no value in many areas. Conodonts do not occur in rocks younger than the Triassic. use of careful standards and the same type of palynomorph in each analysis greatly aid reproducibility. Finally. The chief problems arise with inexperienced workers. Conodont Alteration Index (CAI). where pollen and vitrinite are often absent. with the help of color charts can be carried out by inexperienced personnel. Colors of the specimens thus obtained are determined under a binocular microscope and compared with standards. Although conodonts are composed of carbonate apatite. The first maturity indicator applied to sediments was the Carbon Preference Index. TAI values must be estimated from amorphous debris. Furthermore. conodonts are plentiful in carbonate rocks. Thirdly. leading to an inaccurate assessment of kerogen maturity. where most of the interest is. The technique is simple and quick and can be done even by inexperienced workers. because the organic metamorphism displayed by conodonts is not related to hydrocarbon generation or destruction. CAI is only an indirect indicator of hydrocarbon maturity. the CAI scale is most sensitive at levels of maturity much higher than can be measured by TAI. One disadvantage of CAI measurements is that CAI values can be dramatically increased in the presence of hot brines. which can vary greatly in its chemical and physical properties. When palynomorphs are absent. Carbon Preference Index (CPI). the absence of spores and pollen in the samples. they offer a means of measuring maturity in rocks that do not contain pollen grains or vitrinite. CAI is inexpensive and easy to measure and. Finally.Source Rock Evaluation . Other disadvantages overlap with some of the advantages. most commonly from fossiliferous carbonates.
5%. where the fluorescence that enables us to distinguish between oil-prone and non-oil-prone disappears toward the end of the oil-generation window. The exception to this rule is with amorphous material. In particular.Source Rock Evaluation . Pyrolysis yields are. CONTAMINATION AND WEATHERING Surface Samples -The types of contamination most frequently encountered in surface samples are caused by living organic matter or by spills of oil. This method works fairly well if the kerogen is still within the oil-generation window. In many cases. Like pyrolysis. it can lead to an overly optimistic assessment of the organic richness of the section. in which the input of terrestrial lipids was very limited. of course. vitrinite reflectance measurements offer the best means of recognizing caving. Fortunately. therefore. Walnut hulls and other organic debris are also easy to detect microscopically. It breaks down at high maturity levels. Careful picking of lithologies and comparison with up-hole samples can often recognize caved materials. however. whereas those of oils were almost always below 1. Without additional information. diesel fuel affects both kerogen and bitumen. have low CPI values even when immature. Caving is a particular problem for coals. fewer CPI determinations are made now. In contrast to solid additives. Later it was realized that the decrease in CPI with increasing maturity depends upon the type of organic matter originally present as well as on maturity. Drilling-fluid additives have been a severe headache for petroleum geochemists for a long time. The most common method for taking maturity effects into account in evaluating pyrolysis data is to use a modified van Krevelen diagram to backcalculate the original hydrogen index. Furthermore. This discovery led to the use of CPI as an indicator of maturity. only microscopic analysis is relatively unaffected by maturity. In such cases TOC values will be raised and reflectance histograms will show a large population near 0.2. in the last decade kerogen analyses have replaced bitumen analyses as the routine procedure in source-rock evaluation. Well Samples . and can be removed prior to beginning the analytical sequence. which affect only the kerogen portion of the sample. Contaminants of particular notoriety are diesel fuel. palynological analysis can usually detect the presence of lignosulfonates because of the unique pollen assemblages present in the lignite. Problems with living organic matter are easily avoided by physically removing tiny plant roots and other recognizable debris.52 values (> 1. walnut hulls and other solid debris. TOC values will be raised and vitrinite-reflectance values lowered by the presence of adsorbed diesel. Mold or other surface growth may also be present. because of their friability. because all kerogens have low pyrolysis yields. atomic H/C ratios measure the present day status of the kerogen rather than its original chemical composition. it is impossible to determine which maturation path brought it to that point. As a result. and therefore should be easy to avoid. strongly affected by maturity. but it can be devastating in cuttings samples. rocks deposited in pelagic environments. they can usually be identified with reasonable confidence. Hydrocarbon contamination is rare except in the immediate vicinity of production or where vehicles are used. As long as kerogen particles are not completely black. Atomic H/C ratios must therefore be corrected for the effects of . Caving is not a problem for conventional or sidewall cores.5). It is capable of impregnating sidewall and conventional cores as well as cuttings. however. and lignite from lignosulfonates. of course. ESTIMATION OF ORIGINAL SOURCE CAPACITY Of the three major methods of determining kerogen type.The main causes of contamination among samples obtained from wells are caving and adulteration by drilling-fluid additives.
INTERPRETATION OF SOURCE-ROCK DATA QUANTITY OF ORGANIC MATERIAL Almost all measurements of the amount of organic matter present in a rock are expressed as TOC values in weight percent of the dry rock. They will not function as highly effective source rocks. cutinite. A rock containing 3% TOC is likely to have much more than six times as much source capacity as a rock containing 0. and S3) are expressed in milligrams of hydrocarbon or carbon dioxide per gram of rock sample. We therefore use TOC values as screens to indicate which rocks are of no interest to us (TOC < 0. the kerogen in such lean rocks is almost always highly oxidized and thus of low source potential. Because the density of organic matter is about one-half that of clays and carbonates. In some rocks TOC values between 1% and 2% are associated with depositional environments intermediate between oxidizing and reducing. resinite. fluorescing amorphous kerogen.5% TOC. These raw data are then normalized for the organic-carbon content of the sample. The oil-generative macerals are those of Type I and Type II kerogens: alginite. and thus of limited source potential. Pyrolysis results are normally reported in two ways. claiming. gas-generative.0%). but they may expel small quantities of hydrocarbons and thus should not be discounted completely. As such these quantities are a measure of the total capacity of a rock to release or generate hydrocarbons or carbon dioxide. Smyth (1983). Raw data (S1.5% TOC are considered to have negligible hydrocarbon-source potential. because the type of kerogen preserved in rich rocks is often more oil-prone than in lean rocks. on the basis of deductive reasoning.53 maturation by using a van Krevelen diagram. We must still determine whether the kerogen present is in fact of good hydrocarbon-source quality. Rocks containing more than 1% TOC often have substantial source potential. Interpretation of TOC values therefore does not simply focus on the quantity of organic matter present. where preservation of lipid-rich organic matter with source potential for oil can occur. TYPE OF ORGANIC MATTER Microscopic kerogen-type analysis describes the proportions of the various macerals present in a sample. Furthermore. In interpreting these observations we normally divide these macerals into oil-generative. Nevertheless. Rocks containing between 0. Thus high TOC values are a necessary but not sufficient criterion for good source rocks. has dissented from this pessimistic view.0% TOC are marginal. and inert. however. S2. Many rocks with high TOC values. etc. The amount of hydrocarbons generated in such rocks is so small that expulsion simply cannot occur. the actual volume percent occupied by the organic material is about twice the TOC percentage. TOC values above 2% often indicate highly reducing environments with excellent source potential.5%).5% and 1. exinite. yielding . however. Kerogens in rocks containing less than 1% TOC are generally oxidized. because the kerogens they contain are woody or highly oxidized. These immature H/C ratios can then be used to calculate Go. Gas-generative kerogen is mainly vitrinite.0%). which ones might be of slight interest (TOC between 0. Those rocks containing less than 0. Inertinite is considered by most workers to have no hydrocarbon-source capacity. the direct evidence for such a statement is rather meager.5% and 1.Source Rock Evaluation . have little oil-source potential. and which are definitely worthy of further consideration (TOC > 1. that at least some Australian inertinites can generate significant amounts of oil.
54 values in milligrams per gram of TOC. either from terrestrial macerals (cutinite. Thus. a unified scale for comparing them with Ro values has not been adopted. with CAI of 8 reached in a marble. most other maturation parameters are related to Ro values. Measured hydrogen indices must be corrected for maturity effects by using a modified van Krevelen diagram as outlined above. COALS AS SOURCE ROCKS Coals have been traditionally discounted as effective source rocks for oil accumulations because of the lack of geographic correlation between oil fields and coal deposits. because they vary with kerogen type as well as maturity. make sure that you have a copy of their equivalency between TAI and Ro.5% Ro. for most kerogens the onset of oil-generation is taken to be near 0. others use 440°. if you are using TAI determinations determined by an analytical laboratory. the hydrogen index serves as an indicator of kerogen type. They have excellent potential to generate liquid hydrocarbons. Because variations in TOC have been removed in the normalizing calculation. Age of coals is important. Because some Cenozoic land plants are richer in resins and waxes than Paleozoic plants. resinite. However. Hydrogen indices above 150 reflect increasing amounts of lipid-rich material. The limits of the oil generation window vary considerably depending upon the type of organic matter being transformed. A second.6% Ro. and the end of liquid-hydrocarbon generation is thought to be at about 1. The normalized S2 and S3 values are called the hydrogen index and the oxygen index. this generalization has two fallacies: most of the coalfields originally studied were of Paleozoic age.35% Ro. Determination of the oil-generation window in a particular section is the objective of most maturity analyses performed on possible source rocks.Source Rock Evaluation . Interpretation of hydrogen indices for immature kerogens is straightforward. Nevertheless. Kerogens with hydrogen indices above 600 usually consist of nearly pure Type I or Type II kerogens. Those between 150 and 300 contain more Type III kerogen than Type II and therefore have marginal to fair potential for liquids. Conodont Alteration Index (CAI) values ranging from 1 to 5 were tied loosely to vitrinite reflectance and fixed carbon content of coals. Kerogens with hydrogen indices above about 300 contain substantial amounts of Type II macerals. Because vitrinite reflectance is the most popular method of determining maturity. The ultimate limit of oil stability is not known for certain. Some laboratories put the onset of maturity at 435° C.9% Ro. because during the Paleozoic the biota was quite different than during the Cenozoic. MATURITY Kerogen Parameters. respectively. and thus are considered to have good source potential for liquid hydrocarbons. Although Tmax values are determined objectively. exinite) or from marine algal material. but there are still some minor variations from one laboratory to another. some Cenozoic coals should have better potential for generating liquid hydrocarbons. less common application is to decide whether oil will be stable in a given reservoir. . The correlations among maturity parameters have been fairly well established. but in most cases is probably not much above 1. It is particularly difficult to generalize about TAI values because the numerical values of TAI scales have not been standardized among laboratories. Hydrogen indices below about 150 mg HC/g TOC indicate the absence of significant amounts of oil generative lipid materials and confirm the kerogen as mainly Type III or Type IV. Peak generation is reached near 0. and the coals were of bituminous to anthracite rank. CAI can actually measure high-grade metamorphism.
20 1.00 1. Whenever possible.0 2.40 0.55 SUMMARY Any source-rock evaluation should attempt to answer three questions: What are the quantity.5 3.0 3. rather.35 1.00 4. we should not rely on a single analytical technique. To do this intelligently we must have the ability to develop regional models of organic facies and thermal maturity.00 Thermal Alteration Index (TAI) 2.50 2.2 3.80 1.60 0. Interpretation of source-rock data on a basic level is quite simple.3 2. type. and organic facies.0 Pyrolysis Tmax (°C) 420 430 440 450 460 465 470 480 500 500 + 500 + Conodont Alteration Index (CAI) 1 1 1 1.6 2. and maturity of the organic matter present in the rocks? Satisfactory methods are available in most cases to answer all these questions.8 4.Source Rock Evaluation . therefore. In some areas one technique may fail completely or may be only partially successful.5 2 2 2 3 4 4 5 Correlation of various kerogen-maturity parameters with vitrinite-reflectance (Ro) values .8 3.00 3. Vitrinite Reflectance (%Ro) 0.50 0.0 4. we should attempt to corroborate the measured data by other analyses. We should always attempt to extrapolate our measured data over as large an area as possible. unconformities and erosional events.4 3. With increasing experience one can also learn to derive important information on thermal histories.
66 0. so "Total Oil" can be plotted against "Oil Already Generated.72 0.7 1.05 0.0 0.77 0.9 3.5 2.5 2-2.5 1.33 1. The calculated immature H/C ratios are listed in the table on next page. one must first convert the measured.Source Rock Evaluation .15 0.5 2.81 1.3 0.22 1.41 0.8 % Alginite + Exinite 75 80 80 75 80 90 85 75 70 50 45 60 45 40 ? ? Core Cuttings Data are available on quantity (%Corg). To use the H /C data.5 0. present-day H/C ratios to the ones that the kerogens had when they were thermally immature.5 2.6 2. refer to the graph on next page.56 EXERCISES Worked out example: Perform a source-rock analysis on the Mauve Well. quality (H /C and %Alginite + Exinite).2 2. and both should be utilized and examined for possible discrepancies.27 1. as shown in Figure B (derived from Figure A).6 2. B) H/C versus TAI for Mauve Well samples.7 3. and maturity (TAI).65 0.3 1." Two independent quality measurements have been made.38 TAI 2.6 0. Source-rock data for the Mauve Well Depth (m) 1000 1200 1500 1750 2000 2300 2700 3000 3500 3600 3800 4000 4500 4600 4800 5000 Type of Sample Sidewall Cores %Corg 0.2 1. This can be done easily by plotting H/C versus TAI.75 0. A) Calculation of the immature kerogen H/C ratio(at A) from the present-day H/C ratio and vitrinite reflectance data(at P) .7 1.1 3.1 2. presenting the kerogen quality factor as a . however.7 2." To do this. Both the immature H / C ratios and the maceral analysis data need to be scaled to calculate "Total Oil.07 1.2 Atomic H/C 1.0 2-2.5 2-2.98 0.2 3.86 0.5 0. and then tracing the H/C ratio back to its immature value.5 1.8 0.6 2.0 3.7 2.
05 0.5 1.05 0.27 1.30 1.41 0.9 1.77 0.60 0. and not . 4000.35 1. Kerogen quality factor as a function of H/C ratio of the immature kerogen.6 1.50 1. 2000.5 1.05 0. In each case.35 0. to check for analytical error.9 0.20 1.90 ? ? Quality Factor Quality Factor (from H/ C) (from 1.86 0.22 1.07 1.5 1.81 1.05 1.77 0.90 0.Source Rock Evaluation .22 1.05 1. If these attempts produced no resolution of the problem.15 0.6 1. The samples at 1000. The prudent interpreter might now ask that some of the H/C ratios be rerun.43 1.8 ? ? * * * Indicates discrepancy between quality factors calculated from H /C and from maceral analysis.90 0. and 4500 meters all show differences in the quality factors calculated from the two types of data. The most important point being made here is that these discrepanties must be taken seriously by the interpreter.6 1. it is impossible to pinpoint the error. so some systematic error is likely.38 Immature H/C 1.66 0. Without more knowledge. In likewise manner (not illustrated here) the quality factor can be determined from maceral analysis data.00 0. and would certainly request that the slides made for maceral analysis be reviewed.57 function of H/C ratio of the immature kerogen in order to determine the quality factor from H/C.65 0.0 0.90 0.60 0. Scaled Quality Data tor Mauve Well Samples Depth (m) macerals) 1000 1200 1500 1750 2000 2300 2700 3000 3500 3600 3800 4000 4500 4600 4800 5000 Measured H/C 1.4 1. 1500.72 0. It is apparent that there are serious discrepanties between the H/C and maceral analysis results for several of the samples. 1750.35 0. such as pyrolysis.07 1.33 1.60 ? ? * * * * * 1.17 0.75 0. the interpreter might then decide to try a third technique.8 1.70 1.2 0.85 1. The scaled quality factors are given for each parameter in the table on next page.7 1.65 0. the H/C ratio gives the lower quality factor.90 0.81 1.98 0. 2300. however.
no maceral analysis was possible here. The relative organic richness of the blackened samples below 4600 meters makes them interesting for further investigation. It may be necessary occasionally to offer two alternative interpretations without choosing between them. because sourcerock potential is not good for most of the section. although the section between 2000 and 3500 meters shows fairly good potential. "Total Oil" values are generally unexciting. about the oil-source history of the section below 4600 meters. Let us take this last approach to this problem. Future exploratory activity could include an attempt to find such a section. The only sample where the discrepancy is significant is that from 2000 meters. . therefore. One can say little. In fact. "Oil Already Generated" values indicate that only the section lying below 4500 meters is likely to have generated anything approaching a commercially attractive amount of oil. a more thermally mature version of the rocks lying between 2700 and 3000 meters in the Mauve Well could already have generated very large quantities of oil.Source Rock Evaluation .58 be overlooked or swept under the rug. "Total Oil" and "Oil Already Generated" profiles tor the Mauve Well. These two kerogens are highly mature and quite black. The rest of the section shows a good correspondente between the two parameters. Finally. More samples between 3000 and 3500 meters should be obtained to define better the zone of high "Total Oil" values. and the H/C ratios are not helpful because the maceral types cannot be ascertained from such low H/C values. except for the two deepest samples. Most of the discrepanties among the different quality factors turn out to be unimportant. "Total Oil" and "Oil Already Generated" profiles are plotted in above figure.
4 0.52 0.05 0.5-3 2.0 0.5-3.08 0. EXERCISE Source Rock 2 Perform a source-rock evaluation of the section penetrated in the Turquoise Well.02 0.42 0.0 2.5-3 2.0-2.51 0.6 0. Explain how you resolved any apparent discrepancies.03 0.0-2.17 0.5-3 2.02 0.6 2.08 0.55 0.2 0.41? 1.5 2.49 0.06 0.5-3 2.5-3 2.5 2.65 0.5 3.65 0.60 0.59 EXERCISE Source Rock 1 Combine the data from the Blue Well to give a coherent picture of thermal maturity in the section drilled.06 0.09 0.07 0.3 1.25 1.17 0.3 2.7 0.63 0.60 0.25 0.1 2.48 Ro 0.44 0.5 2.Source Rock Evaluation .51 0.1 0.49 0.5 2.27 1.0 2.07 1.61 0.2 2.5 TOC = Total Organic Carbon Bit/TOC = Bitumen/Total organic carbon ? indicates a poor histogram TAI = Thermal Alteration Index Ro = Vitrinite reflectance .88 0.5 2.000 Type of Sample Cuttings Cuttings TOC 1.5 2. Thermal-maturity data for the Blue Well Depth (ft) TAI Ro Bitumen/TOC 1000 1200 1500 2000 2300 2600 3000 3200 3400 3700 4000 4200 4800 5000 5200 5400 5700 6000 2.0 2.01 0.99 1.5-3 3.5 2.12 *TAI and Ro are interconverted according to the correlation table at the end of chapter 7.11 0.66 0.05 0.90 0.3 2.60 0.06 0.5 2.21 1.5 2.21 0.22 0.08 0.85 0.67 0.91 0.3 Bit/TOC 0.0 2.26? 1.51 TAI % Alginite + Exinite 40 30 35 40 50 80 75 75 25 40 70 80 20 15 10 2-2.91 1.27 0.9 1.46 0.5 2.18 0.33? 1.66 0.21 1.0 3-3.03 0.8 1.09 0.59 0.86 1.91 1.02 Atomic H/C 0.0 2. Source-rock data tor the Turquoise Well Depth (ft) 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10.0-2.5 0.00 1.5 3-3.08 0.7 0.71 0.10 0.51 0.0 2.5 3.59 0.8 0.07 0.5 2.3 2.03 0.6 4.
Lopatin's method allows one to predict both where and when hydrocarbons have been generated and at what depth liquids will be cracked to gas. Even in maturely explored basins the samples available for analysis often do not give a representative picture of maturity in the basin. If no subsurface data are available. a time stratigraphy can sometimes be constructed using seismic data. Nevertheless. If no well data are available. however. estimates can be made. In most cases. perhaps from thicknesses of exposed sections nearby. however. early efforts to take both time and temperature into account in studying the process of hydrocarbon generation were only partially successful because of the mathematical difficulties inherent in allowing both time and temperature to vary independently. and migration with timing of structure development or trap formation. .Predicting Thermal Maturity INTRODUCTION Measured maturity values for possible source rocks are invaluable because they tell us much about the present status of hydrocarbon generation at the sample location. maturity measurements can only tell us about present-day maturity levels. Part of this problem is a consequence of the limitations we face in attempting to obtain reliable maturity measurements. Time-stratigraphic data are usually available as formation tops and ages obtained by routine biostratigraphic analysis of well cuttings. in frontier basins there may not be a single well within tens or hundreds of kilometers. In this chapter you will learn how to carry out maturity calculations using Lopatin's method and how to use Lopatin's method in exploration. we still have no clue as to when oil generation occurred. for it is in keeping with the predictions of chemical-kinetic theory. methods have been developed for calculating maturity levels where measurements are not available. In 1971. nor do we know at what depth or temperature it occurred. If our measurements indicate that a rock has already passed through the oil-generation window. expulsion.60 9 . It has even been suggested that maturity models are more accurate than measured data for determining the extent of petroleum generation. measured maturity data are of limited value in exploration. In some areas there are no well samples available. CONSTRUCTION OF THE GEOLOGICAL MODEL One of the advantages of Lopatin's method is that the required input data are very simple and easy to obtain. indeed. especially if the seismic reflectors can be tied to well data. This assumption is a logical and defensible one. These considerations are important when we want to compare timing of generation. The common thread running through all these models is the assumption that oil generation depends upon both the temperature to which the kerogen has been heated and the duration of the heating. Furthermore. These two factors are interchangeable: a high temperature acting over a short time can have the same effect on maturation as a low temperature acting over a longer period.Predicting Thermal Maturity . Lopatin in the Soviet Union described a simple method by which the effects of both time and temperature could be taken into account in calculating the thermal maturity of organic material in sediments. He developed a "Time-Temperature Index" of maturity (TTI) to quantify his method. In order to circumvent these difficulties. We need data that will enable us to construct a time stratigraphy for the location of interest and to specify its temperature history.
Suppose further that local weather records indicate a yearly average surface temperature of 19° C.(9-2) All of the shallower and younger horizons will have burial-history curves whose segments are parallel to those of the oldest horizon. The subsurface temperature must be specified for every depth throughout the relevant geologic past. Connecting the six dots completes the burial-history curve. for example. Suppose. TEMPERATURE HISTORY The next step is to provide a temperature history to accompany our burial-history curve.61 BURIAL-HISTORY CURVES Implementation of Lopatin's method begins with the construction of a burial-history curve for the oldest rock layer of interest. and that a corrected bottom-hole temperature of 133° C was obtained at 3800 m. Using these present-day data and extrapolating them into the past. by 80 Ma the sediment had been buried to a depth of 900 m (point C). which was constructed from the time stratigraphy for the Tiger well. Burial-history curves are based on the best information available to the geologist. Using the other control points from the input table. This geometry is a direct consequence of ignoring compaction effects. we can construct the complete figure. The burial-history curve was constructed in the following way: two points. In cases where biostratigraphic data are lacking or where the sediments have had complex tectonic histories. sediment has accumulated continuously but at varying rates since deposition of the oldest rock 100 million years ago (Ma). Nevertheless. The next step is to locate the first control point from the time-stratigraphic data on the input table. if constructed as carefully as the data permit. In cases where biostratigraphic data are available and deposition has been reasonably continuous. Today the rock is at a depth of 3700 m. that the Tiger well was logged. are marked on the age-depth plot. Neglecting compaction effects. it is easy to construct burial-history curves with a high level of confidence. The simplest way to do this is to compute the present-day geothermal gradient and assume that both the gradient and surface temperature have remained constant throughout the rock's history. representing the initial deposition of the sediment (point A) and its position today (point B). a burial-history curve may represent only a rather uncertain guess. burial-history curves represent our best understanding of the geological history of an area.Predicting Thermal Maturity . we can construct the temperature grid with equally spaced isotherms parallel to the earth's surface. . An example is shown in the following figure. In the Tiger well.
maps of regional geothermal gradients can be useful in estimating the gradient at a particular location. the data necessary for highly sophisticated temperature reconstructions are simply not available. we can change surface temperatures through time without altering the geothermal gradient. some part of the section is repeated as a result of thrusting. but the geothermal gradient varies in response to heating or cooling events. The individual segments of each of the burial-history curves in a family will remain parallel. In many poorly explored areas. Faulting can be dealt with by considering the hanging wall and footwall as separate units having distinct burial histories. the resultant thinning of the section must be represented in the entire family of burial-history curves. If deposition resumes later. Whenever erosional removal occurs. however. two separate diagrams should be used for the sake of clarity. Causes for such events could include global warming and cooling or local climatic variations resulting from continental drift or elevation changes. For example (9-7).Predicting Thermal Maturity . the burial-history curve again begins to trend downward. There is no theoretical limit to the complexity that can be introduced into our temperature histories. The effects of thrusting on thermal maturity are not well understood. temperature profiles will be based largely on guesswork. we are limited only by our own creativity. There are numerous other variations that can be employed in creating temperature grids. however. If. Given adequate data or an appropriate model on which to base complex temperature reconstructions. In most cases.62 Where measured bottom-hole temperatures are not available. the movement of hot rocks from the bottom of the overthrusted slab over cool rocks at the top of the underthrusted slab will affect . As an example: lowering the geothermal gradient by rapid sediment accumulation results in subsurface temperatures that are anomalously low compared to the "normal" ones that dominated previously. In other cases the surface temperature remains constant. More complicated temperature histories account for changes in thermal conductivities caused by variations in lithology. Erosion is indicated in a burial-history curve by an upward movement of the curve. If thrusting is rapid compared to the rate of thermal equilibration between thrust sheets. If part of the section is missing as a result of faulting. burial-history curves for both hanging wall and footwall can be represented on a single diagram. SPECIAL CONSIDERATIONS ABOUT BURIAL-HISTORY CURVES The most common complicating factor in constructing burial-history curves is erosional removal.
However. spent by the rock in each temperature interval. Individual burial-history curves remain parallel. more work is required before we will understand fully how thrusting influences hydrocarbon generation and destruction. Lopatin chose the 100°-110° C interval as his base and assigned to it an index value n = 0. This intervalTTI value represents the maturity acquired by the rock in that temperature interval during the time .Predicting Thermal Maturity . increases exponentially with increasing temperature. Total maturity is calculated by summing the incremental maturity added in each succeeding temperature interval. Studies in the Overthrust Belt of Wyoming indicate that a slow-equilibration model is superior to a simple model invoking rapid thermal equilibration. Chemical reaction-rate theory states that the rate of a reaction occurring at 90° C (a reasonable average for oil generation) and having a pseudoactivation energy of 16. Intersections of the burial-history curve with each isotherm are marked with dots. Now we can carry out the maturity calculations. Lopatin defined each time factor simply as the length of time. in contrast. respectively. Index values increase or decrease regularly at higher or lower temperatures intervals. These dots define the time and temperature intervals that we shall use in our calculations. decreases by 1000 m. Loss of 1000 m of section by erosion during an uplift event lasting from 70 Ma to 60 Ma. but the distance between the two lines which bracket the erosion. Lopatin (1971) assumed that the rate of maturation followed this doubling rule. Testing of his model and the successful application of Lopatin's method in numerous published examples have confirmed the general validity of this assumption.(9-12) CALCULATION OF MATURITY Once the burial-history curves and temperature grids have been constructed. we need to define both a time factor and a temperature factor for each temperature interval. expressed in millions of years. A Time interval is the length of time that the rock has spent in a particular temperature interval.63 organic maturation by causing important perturbations in subsurface temperatures.400 cal/mol will approximately double with every 10° C increase in reaction temperature. for any temperature interval the temperature factor (?) was given by: ? = 2n The temperature-factor thus reflects the exponential dependence of maturity on temperature. Because the rate of maturation was assumed to increase by a factor of two for every 10° C rise in temperature. Multiplying the time factor for any temperature interval by the appropriate temperature-factor for that interval gives a product called the Time-Temperature Index of maturity (TTI). we must paste them together. Temperature intervals are defined by successive isotherms spaced 10° C apart. In order to carry out maturity calculations conveniently. The temperature factor.
If we put a cake in a cold oven and turn the oven on.(9-20) It is also possible to determine the total-TTI value at any time in the past simply by stopping the calculation at that time. followed by a nonerosional depositional hiatus for the last 50 Ma. where the time factors and yfactors for each temperature interval are shown on the burial-history curve. no matter how much or how rapidly we cool it down. if we forget about the cake when the oven is hot and let it burn. the cake will bake slowly at first but will bake faster and faster as the temperature rises. Maturity always increases. . maturity continues to increase (albeit at a slower rate) because y is always greater than zero. In the adjoining table interval-TTI values and total-TTI values up to the present day are calculated. In D 40 Ma of rapid burial to a depth of 4000 m was followed by a hiatus lasting 30 Ma and. even if a rock cools down. it can never go backward because interval-TTI values are never negative. the specific burial history of a rock can strongly affect its maturity. Figure C shows rapid burial during the first 20 Ma.Predicting Thermal Maturity . baking will continue. as the oven cools down. The first step in calculating TTI is illustrated in the following figure. In A the rock was buried at a constant rate for its entire 80-my history. A good analogy can be drawn between oil generation and baking. To obtain total maturity. If we turn off the oven but leave the cake inside. although at increasingly slower rates. FACTORS AFFECTING THERMAL MATURITY Because maturity is affected by both baking time and baking temperature. Furthermore. TTI values differ appreciably among these four scenarios. In B burial was very slow during the first 70 Ma of the rock's existence. On the other hand. by 10 Ma of uplift and erosion. we cannot "unburn" it. but quite rapid in the last 10 my.64 given. we simply sum all the interval-TTI values for the rock. finally. Four of the many paths by which an 80-Ma-old rock could have reached a present burial depth of 3000 m is indicated in the figure (9-21).
Secondly. Temperature. Most logged temperatures are too low and require correction.(9-29) Furthermore. we usually have excellent control on rock ages through micropaleontology. Age calls are often made within a million years. but there is no guarantee of their accuracy in any particular case. might we anticipate possible problems with time. The hiatus has been reinterpreted as an erosional unconformity (9-23) POTENTIAL PROBLEMS WITH MATURITY CALCULATIONS The most obvious errors in maturity calculations will come from inaccuracies in time and temperature data. Kc = Cody-Frontier formations. in contrast. and can be even better in Cenozoic rocks.65 A) Initial proposed burialhistory model for Well #1. our uncertainties about the true values of subsurface temperatures are much greater than about time. time data are seldom a problem.Predicting Thermal Maturity . . is the single most important cause of uncertainty and error in maturity calculations. Km = Lance-Meeteetse formations. Tu = undifferentiated Tertiary. so even a rather large error in baking time will not produce a catastrophic change in maturity. Wyoming. the dependence of maturity on time is linear. Only in cases where micropaleontological dating was not or could not be carried out. B) Revised burial-history model for Well #1 based on the poor correlation with measured maturity data. showing the evolution of the oilgeneration window through time. First. In actuality. The model includes an extensive nonerosional depositional hiatus. The sensitivity of maturity to temperature is clearly indicated by the exponential dependence of maturity on temperature predicted by the Arrhenius equation. Present-day subsurface temperatures are difficult to measure accurately. Tfu = Fort Union Formation. Various methods have been developed for this purpose. Family of burial-history curves for a well in the Big Horn Basin.
5 2.5-3 2.3 2.150 ft in the Middle Miocene.8 0.51 0.08 0.1 2.18 0.90 0.21 1.5-3.5-3 2. In such cases we should be very careful about using predicted maturities unless we have some independent confirmation of the validity of our model from a comparison with measured maturity data.51 0.66 Even if we could measure present-day subsurface temperatures with perfect accuracy. Source-rock data tor the Turquoise Well Depth (ft) 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10.41? 1.5-3 3.49 0.17 0. Construct a family of burial-history curves for the well and calculate the present-day TTI at total depth.1 0.66 0.5 2. however.25 1. an accurate interpretation of the ancient geothermal history may be critical.00 1.88 0.08 0.21 1.000 Type of Sample Cuttings Cuttings TOC 1.86 1.27 0.91 1.71 0.65 0.8 1. however.7 0. particularly where Paleozoic rocks are involved.02 Atomic H/C 0.06 0.08 0.22 0.6 4.0 0. where presentday temperatures are maximum paleotemperatures.01 0.67 0.5 3. In many cases.52 0. It penetrated 1000 ft of Pleistocene sediments.03 0.5 3-3. 3500 ft of Pliocene.3 1.5-3 2.5-3 2.91 0. EXERCISES EXERCISE Thermal Maturity 1 Perform a source-rock evaluation of the section penetrated in the Turquoise Well.48 Ro 0.03 0.91 1.07 1. A question of some concern comes from the previously mentioned fact that most of the maturity models treat all types of kerogen identically.7 0.5-3 2.85 0.5 2.99 1.60 0.02 0.2 0. A plausible average surface temperature is 20° C. Despite experimental evidence indicating that different kerogens decompose to yield hydrocarbons at different levels of maturity models. we still would have to extrapolate the present somehow into the past.5 0. Base Pleistocene 2 Ma Base Pliocene 5 Base Upper Miocene 11 Base Middle Miocene 50 Ma .05 0.06 0.26? 1. do not utilize different kinetic parameters for the various kerogen types.4 0.59 0. The corrected bottom-hole temperature was 270° F.5 2.27 1. In other cases.0 3-3.65 0.5 3. and 11.33? 1.5 TOC = Total Organic Carbon Bit/TOC = Bitumen/Total organic carbon ? indicates a poor histogram TAI = Thermal Alteration Index Ro = Vitrinite reflectance EXERCISE Thermal Maturity 2 The Black Well was drilled off the Louisiana Gulf Coast.Predicting Thermal Maturity .51 TAI % Alginite + Exinite 40 30 35 40 50 80 75 75 25 40 70 80 20 15 10 2-2.000 ft of Upper Miocene before being abandoned at 16. even an inaccurate extrapolation into the past may not cause significant problems.3 Bit/TOC 0.9 1.
Time-stratigraphic data Temperature data Age (Ma) 0 2 38 65 80 100 Depth (m) 0 500 1200 2700 3000 4000 Present-day average surface temp. assuming a constant geothermal gradient through time. Assuming a surface temperature of 10° C and a geothermal gradient of 2° F/100 ft. Total depth is reached at 6120 ft in Middle Jurassic rocks. Find when the rock at 3000 m began to generate oil (TTI = 10).end Cretaceous: 15° C 141° C 25° C EXERCISE Thermal Maturity 4 The Ultraviolet Well is spudded in Paleocene sediments. Age data top Paleocene base Paleocene base Maastrichtian base Campanian base Santonian base Coniacian 55 Ma 65 73 83 87. micropaleontology indicates the rocks to be of Maestrichtian age. The following Upper Cretaceous boundaries are noted: Maestrichtian-Campanian Campanian-Santonian Santonian-Coniacian Coniacian-Turonian Turonian-Cenomanian 1807 ft 2002 ft 2360 ft 2546 ft 3017 ft The Cenomanian is 480 ft thick and overlies 1000 ft of Kimmeridgian-age shale. Evidence from related sections indicates that the Paleocene was originally about 3000 ft thick and that no other Cenozoic sediments were ever deposited. draw a burial-history curve for the section penetrated and calculate maturity for the Kimmeridgian shale.67 EXERCISE Thermal Maturity 3 Calculate present-day TTI at 3000 m in the Red Well. It is also believed that 500 ft of Lower Cretaceous sediments were deposited before uplift and erosion began. Total original thickness of the Kimmeridgian is thought to be 1500 ft. Determine when each of the strata began to generate oil. At a depth of 1500 ft.5 88.5 base Turonian base Cenomanian base Cretaceous top Kimmeridgian base Kimmeridgian 91 Ma 97 144 150 156 Ma .Predicting Thermal Maturity . Corrected BHT (4200 m): Estimated surface temp.
No other source rocks were noted. The reservoir is sealed by a thick salt layer. Carboniferous '' '' '' '' E. No other reservoirs are anticipated. Carboniferous '' Ordovician '' Depth (ft) 7. The traps at the prospect location formed slightly prior to the beginning of erosional removal in the basin and have retained integrity to the present. Time-stratigraphic data are given in the following table. Erosional removal since the Permian probably totals about 2000 ft. they are in turn overlain at 2750m by a sandstone of excellent reservoir quality. upper management has decided that gas and condensate are not economical. and the surface temperature today is about 15° C.000 13.65°C/100 m and a surface intercept of 15°C are reasonable for the area. The basin filled at a generally uniform rate from about 300 Ma to 100 Ma. Your responsibility is to make a recommendation regarding the nature of hydrocarbons that might be present in die prospect. .500 21.500 27.000 8.500 EXERCISE Thermal Maturity 6 You have been asked to evaluate an undrilled prospect in a remote area that is available in an expensive farm-in deal.000 11.68 EXERCISE Thermal Maturity 5 Analyze the timing of oil generation in the Pink Well.Predicting Thermal Maturity . The source rock is thought to be about 300 Ma old. The geothermal gradient was found to be 1. oil-prone source rock at about 4300m depth near the prospect." Utilizing the principles of hydrocarbon generation and preservation.0° F/100 ft. "A regional study of the area suggests the probable presence of a thin. evaluate the prospect. rich. No unconformities are recognized within the Paleozoic.000 25.000 23. From 40 Ma to the present about 500m of additional burial occurred. At that time nearby orogenic activity caused the first traps to be formed during a gradual 1200m uplift lasting until 40 Ma. Because of the high operations cost. Nearby well control indicates that a geothermal gradient of 3. Top of Permian Virgil Missouri Des Moines Atoka Morrow Mississippian Kinderhook Sylvan Arbuckle Age (Ma) 230 280 288 296 304 309 320 340 425 470 Period Permian 0 L. Highly fractured carbonates overlie the source rock.000 18. The following geological summary is available to you.
Quantitative Assessment . which controls the amounts of oil in the reservoir. This section is included to give an idea of what is involved. of the following terms: OIL IN PLACE This is the total volume of oil. Now we must see how we can apply our knowledge of the geology to assessing the amounts of petroleum that we have found. Recoverable reserves: The volume of oil that can actually be produced to surface from an accumulation. and oil may be produced directly into it. First. This may be done via a standard deviation or by a statistical probability (see below). just what these changes amount to. once a discovery is made. The stock tank is. Proven reserves: Here we start to enter a minefield! Different companies have different definitions of what is proven. It usually refers to what was there originally. Increasingly these days. methods. However. We may distinguish between primary reserves that can be produced without any artificial assistance other than pumping. in the case of small fields. which can be produced using assisted or enhanced recovery techniques. since we are never able to recover all of the oil that is down there in the reservoir. And yet oil companies need to know what to expect. measured in barrels or other units that is present in an accumulation under the ground. and tertiary reserves using more exotic techniques. before we started to take any of it out. however. or predict. let alone how much. and hence the STOOIP refers to the oil in place in the reservoir but corrected to the volume it would occupy under surface pressure and temperature. Note. companies tend to use `proven' for those reserves that are believed to be present with an 85 or maybe 90 per cent degree of . let us again emphasize that we are dealing all the time with uncertainties. even within oil companies. Some might use the term to refer to the amount of recoverable oil that is believed to lie within a given radius. we have to remember that we are dealing with a resource and that we are very concerned with the quantities involved. there is no way that we can know precisely how much we have found: the geology. but the same considerations.69 10 . We will refer to oil. we are involved with a greater or less degree of uncertainty about quantities. located at surface near the well-head. Similarly. and terms can be used equally for gas. So. we have to clear a good deal of misunderstanding and misuse. We cannot regard these quantities as `reserves'. half a mile or whatever. You may see the engineers using the term STOOIP: stock tank oil originally in place. Because anyway there is uncertainty about this amount. or hope to find. RESERVES Perhaps the following explanations will give you some idea of what we are up against when we come to consider quantities of the resource on which a good deal of our civilization depends. it is desirable to be able to express our degree of confidence in it. There is no way of knowing in advance of drilling whether or not there is going to be any oil or gas at all down there under the ground. they might designate as `probable'. unless we can be more specific about how we are going to produce them. is liable to change between our information points. How do we handle these problems? Before we get into this. of a well. our wells.Quantitative Assessment So far we have been talking in rather generalized terms. What they think is beyond that in the accumulation. that the proportion of the oil in place that we can recover will depend on the economics: how much money are we prepared to spend on getting it out of the ground. secondary reserves. We have to try to understand. A bald figure for `recoverable reserves' is somewhat meaningless. until actually all of the oil has been produced. and therefore without any dissolved gas of significance.
if we do. it is the remaining reserves. even when we have information from a lot of wells. – FVF is the formation volume factor. This reflects the fact that oil under the ground in the reservoir occupies more space than it does when we get it up to the surface. but what happens between and beyond our well control? – Sw is the water saturation. to cover the reserves that have only a 15 or 10 per cent chance of being present. and what is still there for the taking at a given date. What anyway should we regard as net reservoir? A rather arbitrary porosity cut-off value is often used. `probable'. that are meant. and the quality and strength of the cap rock. Not all of a reservoir formation is going to be sufficiently porous and permeable to contribute oil to production. and just to qualify our figures by statistical probabilities: at least then people would know what is meant! Original and remaining reserves: These are fairly obvious. faulting. – Fill is the `fill factor'. – N/G is the net to gross ratio. We do our best from measurements on core samples and from wireline log interpretation. and the thickness of the reservoir govern it. We then eliminate progressively everything from this volume that is not oil. Sometimes `possible' is also seen. like `proven'. and `possible' altogether. If we do not know where the gas-oil and oil-water contacts are. We may actually be able to measure the FVF if we have a sample of oil collected under subsurface pressures from the bottom of our well.Quantitative Assessment . Probable reserves: Equally dodgy! One definition was given above: the term may be used. – ? is the porosity. So we multiply the bulk volume of the reservoir in the trap by those factors that represent the non-oil. the percentage of the porosity that is occupied by the immovable water. . meaning that we have to try to interpret in detail the environments that the sediments were deposited in. then we can go straight to the bulk reservoir volume containing the oil. The shape of the trap. and regional and local geological interpretation. It may well be that it is best to avoid the terms `proven'. What this means and how we arrive at the figure. then this factor may be little more than a guess. the higher will be the water saturation. They refer respectively to what was there and recoverable before we started producing. the volume of the gas cap and the water-bearing rock below the oil-water contact being discounted. Usually. or rather the average porosity of the net reservoir across the entire accumulation. This can be pretty subjective. to refer to a degree of confidence or probability. We have not only all the problems of average porosity but remember that the size of the pores comes in here as well: the finer the sand. including the adequacy of the source rock to provide enough oil to the trap.70 confidence or statistical probability. This will be controlled by variations in the nature of the sediments that comprise the reservoir. We have to discount those parts of it that are useless and just consider the net reservoir thickness. we shall see shortly. which is the percentage of the bulk volume that actually contains the oil. in this case 50 per cent. DISCOVERED RESERVES Once a discovery of oil has been made.Sw)] * RF * Constant FVF where: – BV is the volume of the reservoir formation within the closure of the trap above the spill-point. It is affected by many factors. it shrinks because gas bubbles out of it as its pressure is eased during production. Again we need an average value for the field. if we hear simply about `reserves'. Recoverable reserves = [BV * Fill * N/G * ? * (1 . the normal way of estimating how much has been found is to start with the volume of the reservoir within the closure of the trap. BV will be determined from seismic and well data.
and governments must have numbers that they can use for planning purposes. If we plot out the answers on our list falling within successive size ranges (in barrels of oil). having regard to all of the geology. we shall find that the bulk of them tend to cluster round the middle (Fig. So we usually have to base our estimate on prior experience elsewhere. Instead of estimating single figures for the factors that go into the reserves formula. then. It will be clear to anyone that. It is a figure that we cannot know exactly until we have finished producing. The one that has the most answers in (= the modal class of the distribution) we can regard as the most probable value -in other words.). for each of the factors we work out our best estimate. until we begin to wonder whether our answer has any reality or meaning at all. in producing figures for all of these factors. then we don't have to worry. even though they may be well aware that any such figures will eventually turn out to be wrong. since it is about this that the standard deviation can be calculated. A constant is needed to adjust the units. Then we get a computer to pick a value for each factor at random from the range we have given. Note that the preferred answer that is usually used is the mean value. and again. To get an answer to our sum in barrels of oil. Who is right? Whose answer should we use? Can we indeed believe any of them? Unfortunately we cannot escape from the problem.. there must be considerable uncertainty to say the least. however. the problem is tackled through a statistical technique. any one of which could be the real value. and again. and then analysed statistically.Quantitative Assessment . In a sandstone reservoir. maybe 500 or 1000 times. we can work out the standard deviation (the ±) which will give an idea of our confidence in our answer. the proportion of the oil in the reservoir that we can actually recover and produce. So we have a whole list of answers. The Americans measure reservoir volume in acre-feet: area in acres multiplied by reservoir thickness in feet. we give as our preferred figure the average of all the answers (the mean). . somewhere within which the `true' figure must be. and to try to be as honest and objective as possible. The number of answers in successive reserve ranges is plotted against the size ranges themselves. we have to multiply the figure we calculate by 7758. known as a Monte Carlo simulation. from minimum possible to maximum possible. and we also specify the total range. doubtful estimates by doubtful estimates. and arrive at perhaps wildly different answers. our best estimate.. Most commonly these days. companies. but biassing its pick towards our best estimate. but it may be a good deal less from carbonates. More commonly. The list is put into order from the smallest to the largest. is to multiply uncertainties by uncertainties. The computer does the sum using these values. this is commonly about 50-60 per cent. If we are working entirely in the metric system. What we are doing.This is because. Diagrammatic plots of the outputs from two Monte Carlo simulations. for this average value. Then we ask it to do the same thing again.71 – – RF is the recovery factor. Different geologists will certainly come up with different values for at least some of the input factors. Alternatively one may plot the frequencies as percentages of the total number of answers: the statistical probabilities.
we have to go a stage further. as opposed to assessing what we already know to be there. the same values are discounted by a 50 per cent risk factor. for geological reasons. In the lower plot. We try to assess the probability that each factor will be satisfied. one of the main benefits from all of this is that it forces us to think carefully about the geological requirements for oil to be present. now gives a more complete picture of the viability of an undrilled prospect . This is what is used to determine those reserves that may be called proven. and ensures that all possibilities are considered. the curve represents the chance (probability) that the reserves are a certain size or greater. Of course we try to be as scientific. This chance (probability) is known as the risk factor: it is an expression. and then merely combine the probabilities to give an overall probability . of our confidence that there will be at least some oil. It will give a graph which shows the probability that the reserves will be of a certain size or more. that is exactly what it is. Incidently. For example. So this type of graph has now become one of the standard key tools in exploration/development decision. We have to give not only our best estimate of how much petroleum there might be. to give the chance of discovering certain reserves or more including the 50 per cent chance that we may find nothing at all. and possible at. Most usefully.Quantitative Assessment . The risk factor. it doesn't take any account of the fact that our exploration well may. . different geologists will arrive at different figures for the probability of success.at least until we start also considering the costs and economics.72 The output from a Monte Carlo simulation with the percentages plotted cumulatively. and 10 per cent levels of probability respectively. probable. perhaps. It is also used to assist management in making their exploration/development decisions. When it comes down to risk. the 90. objective. The way it is commonly approached is to go back to the basic conditions for oil acumulation: all of the essential requirements have to be met if there is to be oil in a particular place and that. turn out to be totally dry-lacking in hydrocarbons. we can plot out the percentages of answers in successive size ranges cumulatively as we work down the list (Fig. UNDISCOVERED RESERVES This is all very well. if any one of them fails or is lacking. there really is no such thing as the risk factor. say. but also the chance of there in fact being any oil at all. then no oil.the risk factor. but rather it is the number an individual geologist might produce to reflect his/her personal interpretation of the geology. you may say. management can then decide whether or not to take the gamble on developing the field at those odds. we can read off from the graph the chances of our field containing that much oil or more. 50. It cannot be worked out completely objectively.). Indeed it does not! When we are looking at exploration of the unknown. It is this sort of thing that helps to make the oil exploration business so competitive. if the engineers say that a field of so many million barrels is going to be needed to justify development and production costs. And if all this sounds like a gambling game. and honest as can be in assessing exploration risk. By plotting the answers from the 100 per cent probability downwards. in numbers. combined with the estimate of how much. but it assumes that we have already discovered oil.
But we have to admit that. We could adopt what is known as a `geochemical material balance' approach. all of them are very dodgy . it is a pretty wild sort of plot. 5. unless we really have a lot of information (we never have enough!). However. and the area under that bit will represent what. Some of these will be successful. we have to assume that today we can identify and assess all of the prospects that ever will be found in the basin. Undiscovered are thus what we hope to find in a prospect area or sedimentary basin in the future. Let us look at the more important ones. on average. to believe that we can do this would be the height of conceit. however. If we have a reasonable amount of information and control. The obvious thing to do is to add together the risked reserves estimates of all the remaining prospects. 3. or would our money be better spent on drilling a smaller but safer one? The risked reserves.). Forcing these experts to agree a figure amongst them might refine the approach. This combines in a single estimate. let us note a number known as the risked reserves. Many `experts' have scratched their heads over the estimation of undiscovered reserves. then the area under it represents the total volume of oil found to date. we can. and use the figures for the known also for the unknown ones. the amount of oil generated. ULTIMATE RESERVES So far we have been talking about a single oil accumulation or a single prospect. This is known as the Delphi technique. We might look at explored and known parts of the basin.Quantitative Assessment . we are said to be consulting the oracles! All of the above techniques have been used. and calculate average quantities of oil per cubic mile of sediment. Should we. We could make comparisons between known and unknown basins. if we draw a smooth line through it to even out the peaks and the troughs. and some may be more appropriate in given circumstances than the others. the built-in risk factor takes care of this. Delphi was the place in ancient Greece where one went to consult the oracle about one's future. for our `best estimate'. Adding this to the original reserves will give us what is sometimes called the `ultimate reserves'-a grand total for the basin. and a number of techniques have been employed. and we should be on our guard against believing that it is what we shall find (it most categorically is not) or otherwise trying to read too much into it.73 Lastly. the two elements of size and chance of success. is a hypothetical figure. However. 6. expelled. go for a large but very risky prospect. get a number of experts to make their forecasts by whatever technique they prefer and. the expected reserve estimates from our Monte Carlo simulation multiplied (discounted) by the risk factor (Fig. and as such can be very useful in planning an exploration program. knowing how rich it is. In a similar vein the amount of oil found world-wide each year from the beginning of the century can be plotted. otherwise we may be doing little more than guessing. 4. merely use the average of the figures they produce. Use past statistics (number of barrels of oil found on average for each 100m of exploration drilling?) and extrapolate to future drilling. qualify it by a statistical probability. This figure is extremely imprecise and may be not much more than a guess. on this tack. for example. If all else fails. however. 1. remains to be found. How now do we estimate what still remains to be discovered over a wider area or even an entire sedimentary basin? There really is no objective way of doing it-but still companies and governments want to know. sometimes in combination. but some will be dry. Extrapolate this smoothing line out into the future. this technique may bring us into the right ball-park. or underlying each square mile of surface area. This kind of plot can be used also for individual basins or for the whole world. There are lots of uncertainties in this but the calculation would be amenable to a Monte Carlo type of simulation. This starts with the volume of mature source rock in the basin and then. 2. and made available for entrapment (the `charge') can be calculated. then use these figures for the unexplored parts of the basin.
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