Hydrocarbons

HYDROCARBONS 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.

HYDROCARBONS

CONTENTS 1 - INTRODUCTION............................................................................................................................. 5 FORMATI0N OF 0IL AND GAS......................................................................................................... 5 2 - ORGANIC FACIES.......................................................................................................................... 6 THE CARBON CYCLE ....................................................................................................................... 6 FACTORS INFLUENCING ORGANIC RICHNESS............................................................................ 7 PRODUCTIVITY .............................................................................................................................. 7 PRESERVATION.............................................................................................................................. 8 DILUTION ..................................................................................................................................... 11 SUMMARY ....................................................................................................................................... 12 3 - ORGANIC CHEMISTRY .............................................................................................................. 13 INTRODUCTION.............................................................................................................................. 13 NAMES AND STRUCTURES........................................................................................................... 13 HYDROCARBONS ......................................................................................................................... 13 NONHYDROCARBONS ................................................................................................................. 15 4 - KEROGEN...................................................................................................................................... 17 INTRODUCTION.............................................................................................................................. 17 KEROGEN FORMATION................................................................................................................. 17 KEROGEN COMPOSITION ............................................................................................................. 18 KEROGEN MATURATION .............................................................................................................. 20 INTRODUCTION ........................................................................................................................... 20 EFFECTS OF MATURATION ON KEROGENS ............................................................................. 21 HYDROCARBON GENERATION................................................................................................... 22 SUMMARY ....................................................................................................................................... 23 5 - BITUMEN, PETROLEUM, AND NATURAL GAS...................................................................... 24 INTRODUCTION.............................................................................................................................. 24 COMPOUNDS PRESENT IN BITUMEN AND PETROLEUM ......................................................... 24 GENERAL CLASSES OF COMPOUNDS ....................................................................................... 24 SPECIFIC COMPOUNDS.............................................................................................................. 25 FACTORS AFFECTING COMPOSITION OF BITUMEN AND PETROLEUM................................ 25 SOURCE AND DIAGENESIS ......................................................................................................... 25 RESERVOIR TRANSFORMATIONS ............................................................................................... 26 COMPARISON OF BITUMEN AND PETROLEUM ....................................................................... 27 NATURAL GAS .............................................................................................................................. 28 SUMMARY ....................................................................................................................................... 28 6 - MIGRATION.................................................................................................................................. 29 DEFINITIONS................................................................................................................................... 29 PRIMARY MIGRATION................................................................................................................... 29 MECHANISMS............................................................................................................................... 29 DISTANCE AND DIRECTION ....................................................................................................... 30 SECONDARY MIGRATION............................................................................................................. 31 MECHANISM................................................................................................................................. 31

Contents

DISTANCE AND DIRECTION ....................................................................................................... 31 ACCUMULATION............................................................................................................................ 32 INTRODUCTION ........................................................................................................................... 32 CLASSICAL TRAPS........................................................................................................................ 33 KINETIC TRAPS ............................................................................................................................ 33 TAR-MAT TRAPS ........................................................................................................................... 34 GAS HYDRATES ............................................................................................................................ 34 EFFECTS ON OIL AND GAS COMPOSITION ................................................................................ 34 SIGNIFICANCE FOR EXPLORATION ............................................................................................ 35 7 - PETROLEUM TRAPS ................................................................................................................... 36 THE REPRESENTATION OF TRAPS .............................................................................................. 36 STRUCTURAL TRAPS ..................................................................................................................... 37 STRATIGRAPHIC TRAPS ................................................................................................................ 41 COMBINATION TRAPS................................................................................................................... 42 HYDRODYNAMIC TRAPS .............................................................................................................. 43 THE RELATIVE IMPORTANCE OF TRAPS ................................................................................... 43 EXERCISES ...................................................................................................................................... 45 8 - SOURCE-ROCK EVALUATION.................................................................................................. 49 DEFINITION OF SOURCE ROCK.................................................................................................... 49 PRINCIPLES OF SOURCE-ROCK EVALUATION .......................................................................... 49 QUANTITY OF ORGANIC MATERIAL .......................................................................................... 49 MATURITY OF ORGANIC MATERIAL.......................................................................................... 49 CONTAMINATION AND WEATHERING....................................................................................... 52 ESTIMATION OF ORIGINAL SOURCE CAPACITY ...................................................................... 52 INTERPRETATION OF SOURCE-ROCK DATA ............................................................................. 53 QUANTITY OF ORGANIC MATERIAL .......................................................................................... 53 TYPE OF ORGANIC MATTER....................................................................................................... 53 MATURITY..................................................................................................................................... 54 COALS AS SOURCE ROCKS ......................................................................................................... 54 SUMMARY ....................................................................................................................................... 55 EXERCISES ...................................................................................................................................... 56 9 - PREDICTING THERMAL MATURITY ...................................................................................... 60 INTRODUCTION.............................................................................................................................. 60 CONSTRUCTION OF THE GEOLOGICAL MODEL ....................................................................... 60 BURIAL-HISTORY CURVES.......................................................................................................... 61 TEMPERATURE HISTORY............................................................................................................ 61 SPECIAL CONSIDERATIONS ABOUT BURIAL-HISTORY CURVES ............................................ 62 CALCULATION OF MATURITY..................................................................................................... 63 FACTORS AFFECTING THERMAL MATURITY............................................................................ 64 POTENTIAL PROBLEMS WITH MATURITY CALCULATIONS ..................................................... 65 EXERCISES ...................................................................................................................................... 66 10 - QUANTITATIVE ASSESSMENT ............................................................................................... 69 OIL IN PLACE .................................................................................................................................. 69 RESERVES........................................................................................................................................ 69 DISCOVERED RESERVES............................................................................................................. 70 UNDISCOVERED RESERVES ....................................................................................................... 72 ULTIMATE RESERVES.................................................................................................................. 73

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1 - 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. Although the transformation process is very complex, with many details still poorly understood, it is known that organic debris derived from plants and algae is best preserved in fine-grained sediments deposited in the absence of oxygen.

Low-temperature chemical and biological reactions (called diagenesis) that occur during transport to and early burial in the depositional environment modify this organic matter. Many of the chemical compounds present in sediments are in fact derived from bacteria, and were formed as dead organic matter was converted to microbial tissues.

Most of this organic matter is transformed during diagenesis info very large molecules, the largest of which are called kerogen. These play a key role as the precursors for oil and much natural gas.

The earliest stage of hydrocarbon generation occurs during diagenesis. Certain microorganisms, called methanogens, convert some of the organic debris to biogenic methane. Formation of biogenic methane has been recognized for a long time, but only within the last few years have we realized that in many areas a large portion of the natura!-gas reserves are biogenic.

As burial depth increases, porosity and permeability decrease, and temperature increases. These changes lead to a gradual cessation of microbial activity, and thus eventually bring organic diagenesis to a halt. As temperature rises, however, thermal reactions become increasingly important. During this second transformation phase, called catagenesis, kerogen begins to decompose into smaller, more mobile molecules. In the early stages of catagenesis most of the molecules produced from kerogen are still relatively large; these are the precursors for petroleum, and are called bitumen . In the late stages of catagenesis and in the final transformation stage, called metagenesis, the principal products consist of smaller gas molecules.

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, or under different diagenetic conditions, are chemically distinct from each other. These differences can have a significant effect on hydrocarbon generation.

Once formed, oil and gas molecules can be expelled from the source rock into more permeable carrier beds or conduits. Migration through these conduits often leads to traps, where hydrocarbon movement ceases and accumulation occurs.

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2 - Organic Facies THE CARBON CYCLE Because oil and gas are generated from organic matter in sedimentary rocks, we need to understand how this organic matter came to be preserved in the rocks. Preservation of organic material is actually a rare event. Most organic carbon is returned to the atmosphere through the carbon cycle; less than 1% of the annual photosynthetic production escapes from the carbon cycle and is preserved in sediments. Oxidative decay of dead organic matter is a highly efficient process mediated largely by microorganisms.

Preservation of organic matter begins with photosynthesis. Some of the organic material in sediments consists of fragments of plants or algae that derived their energy from the sun. A large fraction, however, comprises microbial tissue formed within the sediments by the bacterial transformation of plant and algal debris. Zooplankton and higher animals contribute relatively little organic matter to sediments. 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.

Despite the great imbalance in biomass between terrestrial plants (450 billion metric tons [t]) and aquatic phytoplankton (5 billion t), the yearly productivity of both groups is about equal, as a consequence of the much more rapid reproduction of simple aquatic organisms. Because of

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extensive oxidation of land-plant debris in soils, however, much of the terrestrial organic material is already highly oxidized when it arrives in the sediments.

Although some destruction of organic material occurs during transport to the depositional environment, a great deal of the oxidation of organic matter occurs within the sediments themselves. Total Organic Carbon (TOC) values decrease monotonically through the first 300 meters of burial before levelling out at about 0.1%, suggesting that either depth or organiccarbon content eventually limits diagenesis. Depth could interfere with microbial diagenesis when compaction reduces pore sizes and nutrient fluxes in interstitial waters. On the other hand, the low TOC values could indicate that the remaining organic matter has no more nutritional value, and that the microbes have given up trying to digest it. Each factor may be dominant under different conditions.

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 (20,000,000 billion t) dispersed in fine-grained sedimentary rocks. Only a small fraction of this (10,000 billion t, or about 0.05%) occurs in economic deposits of fossil fuels.

When we consider inefficiencies in discovery and recovery, only one molecule out of about every one million successfully negotiates the journey from living organism to the gasoline pump.

FACTORS INFLUENCING ORGANIC RICHNESS In order for organic-rich rocks to be formed, significant amounts of organic matter must be deposited and protected from diagenetic destruction. The three primary factors influencing the amount of organic matter in a sedimentary rock are productivity, preservation, and dilution.

Productivity is the logical place to begin our analysis, because without adequate productivity, accumulation of organic-rich sediments cannot occur.

PRODUCTIVITY A partial listing of the many factors influencing productivity would include nutrient availability, light intensity, temperature, carbonate supply, predators, and general water chemistry. Each of these categories could in turn be further subdivided. For example, nutrient availability would depend on such factors as water circulation patterns, orogeny and erosion, volcanism, paleoclimate, and recycling by organic decay.

Nutrient availability is, in fact, one of the critical parameters governing productivity. Shallowmarine environments, where there is local recycling of nutrients from decaying organisms and influx of fresh nutrients from terrestrial sources, are therefore much more productive than the open ocean.

In relatively unrestricted marine environments, watercirculation patterns are particularly important for supplying nutrients and thus controlling productivity. Bodies of water naturally develop density stratification, with a preference for horizontal water movement within each density layer. Nutrients dissolved in waters below the photic zone therefore go unutilized, because under normal circumstances they cannot move upward into the zone of photosynthesis.

Only where there is upwelling of subsurface waters can these nutrients return to the photic zone.

Upwelling occurs where bulk movement of surface water away from a particular area allows deeper water to ascend to replace it. If this deeper water is enriched in nutrients, high photosynthetic productivity will occur at the site of upwelling. In the modern world there are zones of intense seasonal upwelling off the west coasts of California, Peru, Namibia, and Northwest Africa that result from the movement of surface waters away from these coasts. There is another zone of seasonal upwelling off the Horn of Africa in the Indian Ocean as a result of

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monsoonal winds that drive surface waters away from the coast. All these areas exhibit high productivity when upwelling occurs.

Theoretical models have been developed to predict upwelling (and consequent productivity) in ancient seas from input data on continental configurations, landmasses, wind and water circulation patterns, and paleoclimates.

Such models are interesting, and may in fact prove useful in future exploration efforts. There are, however, some problems associated with their application. First, productivity is probably not as important a factor as preservation. There are many more organic-rich facies resulting from excellent preservation than from extremely high productivity. After all, if on the average only 1% of organic matter is preserved, increasing preservation rates is a very efficient way to increase organic richness. Secondly, the accuracy with which we can reconstruct continental positions, paleoclimatic conditions, and all the other factors that influence upwelling loci is severely limited, especially in the Palaeozoic.

PRESERVATION The principal control on organic richness is the efficiency of preservation of organic matter in sedimentary environments. Three factors affect the preservation (or destruction) of organic matter: the concentration and nature of oxidizing agents, the type of organic matter deposited, and the sediment-accumulation rate. Of these, oxidizing agents are probably the most crucial factor.

ANOXIA. Because most of the oxidation occurring in the water column, soils, and sediments is biological, and because most biological oxidation processes require molecular oxygen, the simplest way to limit oxidation is to limit the supply of oxygen. All large organisms require oxygen in order to live, although some species can tolerate extremely low oxygen levels (0.5 milliliters (mL) per liter (L)). At lower levels of dissolved oxygen, many species disappear; the remaining individuals often become dwarfed in an effort to survive in a hostile environment. At dissolved oxygen levels below about 0.2 mL/L, essentially the only viable organisms are those that we call anaerobes, microorganisms that utilize materials like sulfate or nitrate ions instead of molecular oxygen as electron acceptors in their metabolic processes.

We call the zone in which oxygen contents are high the oxic zone; the zone where oxygen falls below 0.2 mL/L is called the anoxic zone. Processes that occur in these two zones are called aerobic and anaerobic, respectively. The term dysaerobic has been used to describe processes occurring in the transitional zone (0.2-0.5 mL/L), and we could coin the term dysoxic to describe the zone itself. The term "anoxic" literally means "having no oxygen," hut because of the radical change in biota that occurs at about 0.2 mL/L, its use in practice has been expanded to include very low oxygen levels as well.

Anoxia is of tremendous importance in the preservation of organic matter in sediments, because when the availability of oxygen is limited, diagenesis is restricted to anaerobic processes. These anaerobic processes are inefficient compared with aerobic diagenesis, and are usually limited in scope by the availability of sulfate or nitrate. Thus if anoxia can develop, preservation of organic matter will be much enhanced.

Anoxic sediments are not always easy to recognize, because some of the commonly used indicators of anoxia may be misleading. Anoxic sediments always contain elevated TOC values (generally above 2% and always above 1% ). However, much oxic sediment also contains large amounts of organic matter, especially of woody origin. TOC values alone must therefore be used with caution. The presence of undegraded marine organic material is a strong indication of anoxia, because marine organic matter is consumed preferentially by organisms. Its presence in

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rocks therefore indicates that diagenesis was stopped prematurely, most likely by absence of oxygen.

Color is not a reliable indicator. All anoxic sediments will be very dark gray or black when deposited. Many black rocks, however, are not rich in organic carbon; they often owe their dark color to finely divided pyrite or to particular chert phases. Color should be used mainly as a negative criterion: If a rock is not very, very dark, it cannot represent an anoxic facies.

The presence of pyrite itself can also be deceptive. Although pyrite does indeed form under anoxic conditions, and its presence indicates that the anaerobic reduction of sulfate ion did occur, there is no guarantee that anoxia was present at the sea floor; it may well have developed after burial. Furthermore, anoxia can be very local; 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.

Finally, anoxic sediments show preserved depositional laminae on a millimeter or submillimeter scale. The laminae prove that burrowing fauna were absent, and therefore that dissolved-oxygen levels were below 0.2 mL/L. Conversely, the presence of bioturbation indicates that the bottom waters were not anoxic, although stunted burrows can be used as evidence of dysoxia.

The ultimate implications of anoxia for petroleum exploration are great; it has been estimated, in fact, that most of the world's oil was generated from source beds deposited under anoxic conditions. It therefore behoves us to understand the conditions under which anoxia develops.

STAGNANT BASINS. Truly stagnant basins are actually quite rare; slow circulation or turnover of the water column occurs almost everywhere. Nevertheless, it is instructive to consider complete stagnation, particularly in understanding lacustrine beds. If an isolated body of water is deep enough, and if the climate is subtropical or tropical, then permanent density stratification will arise as a result of temperature differences within the water column. Depths in excess of 200 m are required to prevent mixing during storms, and warm climates are necessary to avoid overturn caused by freeze-thaw cycles. The cooler, denser waters remain at the bottom, leading to the eventual development of a pycnocline (density interface) which prevents interchange between the two layers. Lack of communication between the layers prohibits replenishment of oxygen in the bottom layer. Therefore, once the original oxygen has been consumed in oxidizing organic matter, no more oxygen can enter, and both the waters in the bottom layer and the underlying sediments will become anoxic.

Marine basins are seldom isolated enough to fit well into the stagnant-basin model, but limnic environments often are. Among the ancient lake beds thought to have been deposited in permanently stratified waters are the well-known Green River Shale (middle Eocene, Wyoming), the Elko Formation (Eocene/Oligocene, Nevada), and strata from several basins in China. Lake deposits associated with continental rifting, especially during the Triassic along the margins of the developing Atlantic Ocean, are anoxic in some of the places where they have been penetrated.

Lakes in failed rifts can also contain organic-rich, anoxic sediments. Lakes of the Rift Valley of East Africa are excellent modern analogs receiving much attention from both researchers and explorationists at the present time.

OXYGEN-MINIMUM LAYER (OML). 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.

This oxygen minimum develops when the rate of consumption of oxygen within that layer exceeds the rate of influx of oxygen to it. Consumption of oxygen results from decay of dead organisms that have sunk from the photic zone above. The oxygen minimum layer usually begins immediately below the photic zone, where photosynthesis and turbulence can no longer contribute oxygen to the water. The supply of fresh oxygen is therefore limited to horizontal

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movement of oxygen-bearing waters. However, because these horizontally moving waters also lie within the oxygen minimum layer, the oxygen they can contribute is limited. Below the OML oxygen levels again increase, as a result of diminished oxygen demand, since most organic matter was destroyed within the overlying OML. Although an oxygen-minimum layer exists virtually everywhere in the ocean, its intensity varies greatly. Intensely developed OMLs occur in areas of high productivity and, to a lesser extent, in areas of poor circulation. Wherever an intensely developed OML intersects the sediment-water interface, sediments will be deposited under low-oxygen conditions. Any organic matter arriving in those sediments will have an excellent chance to escape oxidation.

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. In contrast, foreset beds within the same system are leaner in organic matter because they are deposited above the OML. There are other ancient and modern examples of organic-rich rocks deposited under anoxic or near-anoxic conditions associated with OMLs. 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.

It has been proposed that at certain times in the past (e.g., mid-Cretaceous, Late jurassic, Late Devonian) the world oceans were severely depleted in dissolved oxygen. This depletion was probably the result of the complex interplay of several factors, including paleoclimate and water circulation. During those times the OML expanded both upward and downward because of poor supply of oxygen to subsurface waters. In times like the mid-Cretaceous, when a major transgression had greatly increased the continental shelf area, an upward expansion of the OML led to a tremendous increase in the surface area covered by anoxic bottom waters. It is not coincidental that these were times of deposition of large amounts of organic-rich rocks in many parts of the world.

RESTRICTED CIRCULATION. Settings in which circulation is restricted are much more common than stagnant basins. Furthermore, because of their connection with the open-marine realm, those environments can also incorporate the features of an oxygen-minimum-layer model.

Shallow Silling. Circulation is often restricted by the presence of a sill, the point of connection between the restricted area and the open-marine environment. Where the sill is shallow, the waters entering or leaving the basin are near surface. In an evaporitic environment (Karabogaz in the Caspian Sea) there is a net flow of water into the basin, whereas in a fluvially dominated system (Black Sea) the net flow of surface water is out over the sill. In either case, if the basin is deep enough, permanent density stratification will develop, with the bottom layer almost isolated from the open-marine waters. In actuality there is a lazy turnover of the bottom waters, but it is too slow to disturb the anoxia which develops in the bottom layer.

Shallowly silled basins often yield evaporites, which could be excellent hydrocarbon source rocks. Evaporitic environments combine the opportunity for abundant growth of algae with ideal conditions for preservation. Nutrients are concentrated by evaporation, and grazers and predatory organism are eliminated by the high salinities. High productivity reduces oxygen levels, and high hydrogen-sulfide concentrations create conditions poisonous to predators. The result is often deposition of organic-rich laminae within evaporites, or as lateral facies equivalente thereof.

Coal Swamps. Large amounts of organic material are preserved in coal swamps as a result of the combined effects of poor water circulation, high influxes of organic matter, and diminished bacterial activity. Coal swamps can develop under a variety of conditions in both marine and non-marine environments. Although circulation in coal swamps is generally sluggish, the shallowness of the swamps prevents the waters themselves from becoming anoxic. Anoxia

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develops within the sediments rather than in the water column. Phenolic bactericides derived from lignin hinder bacterial decay in the water and throughout the sediment column. Lack of sulfate in non-marine swamps further prevents anaerobic microbial destruction of the organic matter.

Coals are important source rocks for gas accumulations, but their supposedly low potential for generating oil is to be reconsidered.

Oxic Settings. Most depositional settings not specifically catalogued above will be more or less well oxygenated, and therefore wi11 contain primarily oxidized organic matter. Near-shore oxidizing facies sometimes have high TOC values, but the organic material is almost invariably woody. Abyssal sediments are notoriously low in organic carbon as the result of the combined effects of high oxygen levels in abyssal waters, very slow sedimentation rates, and low productivity in the overlying pelagic realm. The hydrocarbon-source potential of all of these oxidizing facies is low, and more favorable for gas than for oil.

TYPE OF ORGANIC MATTER. Organic matter of algal (phytoplanktonic) origin is consumed more readily by organisms than are other types of organic material, because its chemical components are digestible and provide precisely the nutrients required by scavengers and predators. Nitrogen and phosphorus are in particular demand; their virtual absence in much terrestrial organic material, especially in structural (woody) material, renders it of little nutritional value. Furthermore, the phenolic components present in lignin-derived terrestrial material are toxic to many micro-organism, thus preventing extensive diagenesis of such material.

Any extensive organic diagenesis is therefore likely to eliminate algal organic matter first. That material which remains is dominantly of terrestrial origin, and may include woody, cellulosic, lignitic, cuticular, or resinous material, all of which are chemically quite distinct from each other.

It may also contain very resistent organic debris derived from erosion of ancient rocks, forest fires, and other oxidative processes.

RAPID SEDIMENTATION AND BURIAL. Rapid sedimentation and burial con also enhance preservation. TOC values increase as sediment-accumulation rates increase, as a result of more rapid removal of organic material from the zone of microbial diagenesis.

Rapid burial is accomplished by a high influx of inorganic detritus, biogenic inorganic sediment, or organic material. Rapid deposition of inorganic detritus is common in turbidites and in prodelta shales. The extremely high accumulation rates for biogenic carbonates and siliceous sediments in zones of high productivity promote preservation of the associated algal protoplasm. Coals also accumulate very rapidly and, with their high concentrations of organic matter, provide an ideal means of maintaining low-oxygen conditions.

Rapid settling of organic debris through the water column is also important, because extensive decomposition occurs during its fall to the ocean floor. In fact, much of the organic material that does reach the bottom in deep waters arrives in relatively large fecal pellets, which settle several orders of magnitude faster than individual phytoplankton.

DILUTION Although high sediment-accumulation rates enhance preservation of organic matter, at very high accumulation rate dilution may become a more important factor than increased preservation.

Dilution does not reduce the total amount of organic matter preserved, but it does spread that organic material through a larger volume of rock. The net result is a reduction in TOC values.

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Dilution effects depend upon rock lithology. Biogenic sediments, in which the organic and inorganic materials arrive together, are not as strongly affected by dilution. Shales, in contrast, show strong dilution effects when accumulation rates are very high. Facies changes from carbonates to shales may create large dilution effects that can be wrongly interpreted as indicating changes in oxygen levels.

SUMMARY There are three principal factors that affect the amount of organic matter in sedimentary rocks: primary photosynthetic productivity, effectiveness of preservation, and dilution by inorganic material. Of these, preservation is generally the most important.

Productivity can be predicted by locating ancient sites of marine upwellings. Our ability to make accurate predictions is limited, however, by uncertainties about exact continental positions and configurations in the past, lack of knowledge of seawater chemistry and nutrient availability at those times, and a very imperfect understanding of oceanic- and atmospheric-circulation patterns.

Consequently, such models are not yet of much practical value for the distant past.

Preservation is best accomplished where oxygen is excluded from bottom waters. There are a number of mechanisms by which oxygen depletion may be fostered and maintained, including stagnancy or near-stagnancy, a strongly developed oxygen-minimum layer, and rapid burial. It is often very difficult to separate the influences of these various factors in a particular depositional environment.

Rapid accumulation of sediment shortens the residence time of organic matter in the zone of diagenesis and thus promotes preservation. If the rapidly accumulating sediment is mainly clastic, however, dilution effects may lead to lower TOC values in spite of enhanced preservation rates. In biogenic sediments or coals, in contrast, where sediment-accumulation rates are directly proportional to organic-carbon-accumulation rates, dilution is far less marked.

Because of its role in creating rocks with excellent hydrocarbon-source potential, anoxia in bottom waters is a phenomenon whose effects we should learn to recognize in ancient rocks.

Some of the commonly applied criteria are apt to be misleading, however. It is important to be able to distinguish local anoxia or anoxia developed deep within sediments from anoxia induced by anoxic bottom waters. The most reliable criteria for bottom-water anoxia are the preservation of fine depositional laminae, and the presence of high TOC values coupled with the occurrence of undegraded marine organic matter.

Anoxic events in the past were probably not as large in scale or as long lasting as some workers have suggested. Although certain periods undeniably contain more than their share of anoxic rocks, anoxic sediments were deposited discontinuously through time and space. Direct control of the anoxia was thus probably local, as a result of high productivity or sluggish circulation. As in the modern oceans, such events were often interrupted for long periods before anoxia was reinduced.

Models that integrate the concepts of organic richness with depositional cycles and facies analysis will be valuable tools for understanding hydrocarbon systems in basins. 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.

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3 - Organic Chemistry INTRODUCTION Anyone who uses petroleum geochemistry must be familiar with basic chemical terminology. 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. This objective is very different trom that of a normal course in organic chemistry, in which one must also learn all the reactions of many classes of compounds. The chemical reactions of interest to us are very few and are discussed only briefly. All compounds containing carbon atoms, except carbon dioxide, carbonates, and metal carbides, are termed organic. This usage is historical and does not imply that all such compounds are necessarily derived from living organisms. Organic chemistry is thus the study of carboncontaining compounds, and organic geochemistry the study of organic compounds present in geological environments.

NAMES AND STRUCTURES HYDROCARBONS In chemical terms a hydrocarbon is a compound containing only the elements carbon and hydrogen.

Petroleum and natural gas are themselves often referred to as "hydrocarbons," but that usage is incorrect trom the chemist's point of view because those materials often contain substantial amounts of nitrogen, sulfur, oxygen, trace metals, and other elements. In this chapter we restrict the usage of the term hydrocarbon to the standard chemical one; elsewhere in this text usage will vary, as it does in the real world.

Examples of hydrocarbons are methane, ethane, and cyclohexane, whose structures are shown below.

In each of these compounds, and indeed in every carbon compound (except a few highly unstable ones created only in laboratories), every carbon atom forms four bonds. Similarly, hydrogen always forms one bond; oxygen and sulfer, two bonds; and nitrogen, three bonds. Carbon atoms like to form bonds with each other, creating long chains and ring structures. This unique property of carbon is responsible for the existence of literally millions of different organic compounds.

Writing the detailed structure of a simple molecule like methane is no problem, especially if one has to do it only occasionally. If one wants to draw large molecules, however, the explicit inclusion of every atom and every bond becomes extremely tedious. Several different types of shorthand have therefore developed to facilitate drawing organic molecules.

One common convention is to represent all the hydrogen atoms attached to a given carbon atom by a single H, using a subscript on the H to denote the total number of hydrogens around that atom.

The structures of methane and ethane are thus represented by CH4 and CH3CH3 respectively.

We can make other logical simplifications for longer carbon chains. The following representations of n-pentane are equivalent: CH3CH2CH2CH2CH3 or CH3(CH2)3CH3.

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An even quicker shorthand that uses no letters at all has evolved. Each carbon atom is represented by a point, and carbon-carbon bonds are shown as lines connecting those points. Hydrogen atoms and bonds to hydrogen atoms are not shown at all. Because we know that each carbon atom forms four bonds and each hydrogen atom forms one bond, simple inspection shows how mant' hydrogen atoms each carbon atom must have. For example, n-pentane and cyclohexane are represented by the line structures shown below.

The zigzag configuration illustrated for n-pentane is adopted to show clearly each carbon atom.

The simplest series of hydrocarbons has linear structures; these molecules are called n-alkanes or nparains. The letter n stands for normal, and indicates that there is no branching in the carbon chain. We have ahready encountered n-pentane; the names of the other nine simplest n-alkanes are given in the following table. Note that the name of each compound ends in -ane, as in "alkane." The first four names are irregular, but the prefixes denoting the number of carbon atoms in the other alkanes are derived from Greek numbers.

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. Branching can occur, giving rise to a vast number of possible structures.

The term methyl, which we used earlier, is the adjectival form of the word methane. In the case of 2methylhexane (C7H16) the basic structure is hexane; a CH3 (methyl) group is attached to the second carbon atom. Other adjectival forms are made by dropping the -ane ending and adding yl (for example, ethyl and propyl).

Among the most important branched hydrocarbons in organic geochemistry are the isoprenoids.

Regular isoprenoids consist of a straight chain of carbon atoms with a methyl branch on every fourth carbon. Isoprenoids ranging in length from six to forty carbon atoms have been found in petroleum and rocks.

We have also seen that carbon atoms can be arranged in rings. These cyclic compounds (called naphthenes) are named by counting the number of carbon atoms in the ring and attaching the prefix cyclo.

All the compounds mentioned above are called saturated hydrocarbons or saturates, because they are saturated with respect to hydrogen. That is, no more hydrogen can be incorporated into the molecule without breaking it apart.

Another important group of hydrocarbons is the unsaturates, which, in contrast, are able to combine with additional hydrogen. Many unsaturated compounds have carbon-carbon double

Organic Chemistry - 15

bonds; these compounds are called alkenes. Examples are ethene (C2H4) , propene (C3H6), and cyclohexene (C6H10), the structures of which are shown below. They are named in a similar manner to the alkanes, except that the ending -ene indicates the presence of a double bond.

Because alkenes are highly reactive, they do not long persist in geologic environments. In the laboratory they are readily converted to alkanes by the addition of hydrogen in the presence of a catalyst. By hydrogenation ethene thus reacts to form ethane.

A variety of reactions, including hydrogenafion, converts alkenes to alkanes and cyclic compounds during diagenesis.

Aromatics form an extremely important class of unsaturated hydrocarbons. At first glance aromatics appear to be nothing more than cyclic alkenes containing several double bonds, but they actually have completely different chemical properties from alkenes and are unusually stable.

Although they are unsaturated, they do not add hydrogen easily. Their stability permits aromatics to be important constituents of oils and sediments.

Aromatics possess a system of alternating single and double bonds within a cyclic structure. A simplified notation for drawing these molecules permits us to represent the double-bond system by a circle within the ring. The circle indicates that the electrons in the double bonds are delocalized; that is, they are free to move throughout the cyclic system instead of being held between two particular carbon atoms. It is this delocalization of electrons which makes aromatic compounds very stable.

Some aromatic molecules are very large. Polycyclic aromatic hydrocarbons having fused ring structures are quite common. The extreme case is graphite, which is an almost-endless sheet of aromatic rings.

The hydrocarbons we discussed so far are relatively simple molecules. Although they are very important constituents of petroleum, these compounds are quite different trom the majority of the organic molecules found in living organisms. Most biological molecules are larger and more complex than the simple hydrocarbons; the majority contain oxygen, nitrogen, phosphorus, sulfur, or other elements. The hydrocarbons present in petroleum are mostly the end products of extensive degradation of biogenic molecules. In fact, some complex hydrocarbons that are found in fossil organic material can be related directly to individual biological precursors.

NONHYDROCARBONS Atoms other than hydrogen and carbon that occur in petroleum, bitumen, and kerogen are called heteroatoms; the compounds in which they occur are called heterocompounds. Heterocompounds are also called NSO compounds, because the most common heteroatoms are nitrogen, sulfur, and oxygen. Fossil organic matter often contains a vide variety of heterocompounds, of which some are biogenic and others are formed during diagenesis. Many of the heterocompounds present in organisms are converted to hydrocarbons during diagenesis and catagenesis.

Many common NSO compounds are not directly related to biogenic precursors. Among the most important NSO compounds are the asphaltenes, which are large, highly aromatic materials of

Organic Chemistry - 16

varying structure. They have many characteristics in common with kerogen, but asphaltene molecules are smaller and more aromatic than most kerogens.

Many nonhydrocarbon molecules common to living organisms are also present in sediments. Among these are lignin, carbohydrates, and amino acids. Lignin is an important component of wood, providing much of the structural support for large land plants. It is a polymer consisting of many repetitions and combinations of three basic aromatic subunits.

Lignin monomers are linked topether to form molecules having molecular weights from 3000 to 10,000 atomic mass units. Upon decomposition lignin forms phenolic compounds, which are aromatics having a hydroxyl group (OH) attached. Because phenols are potent bactericides, lignin is rather resistant to degradation, and thus tends to become concentrated as other organic matter is decomposed.

Carbohydrates include starch, sugars, and cellulose; the latter is the most abundant organic compound in the biosphere. Like lignin, it is an important constituent of terrestrial organic matter.

Although cellulose is quite resistant to decomposition under some conditions, most carbohydrates are attacked readily by microorganisms. Lignin and cellulose are major constituents of humic coals.

Amino acids are the building blocks of proteins. They are rapidly metabolized by virtually all organisms, however, and thus are seldom preserved in sediments (exceptions occur in shell material and in bones, where small amounts of preserved amino acids can be used to date specimens)

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4 - 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 soluble portion, called bitumen, will be discussed in a following chapter. Lack of solubility is a direct result of the large size of kerogen molecules, which have molecular weights of several thousand or more. Each kerogen molecule is unique, because it has patchwork structures formed by the random combination of many small molecular fragments.

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.

Kerogen composition is also affected by thermal maturation processes (catagenesis and metagenesis) that alter the original kerogen. Subsurface heating causes chemical reactions that break off small fragments of the kerogen as oil or gas molecules. The residual kerogens also undergo important changes, which are reflected in their chemical and physical properties.

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. Diagenetic and catagenetic histories of a kerogen, as well as the nature of the organic matter from which it was formed, strongly influence the ability of the kerogen to generate oil and gas. A basic understanding of how kerogen is formed and transformed in the subsurface is therefore important in understanding how and where hydrocarbons are generated, whether these hydrocarbons are mainly oil or gas, and how much oil or gas can be expected.

The term kerogen was originally coined to describe the organic matter in oil shales that yielded oil upon retorting. Today it is used to describe the insoluble organic material in both coals and oil shales, as well as dispersed organic matter in sedimentary rocks. 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, oil, and natural gas.

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. Algal (boghead) coals are formed in environments where the source phytoplankton lack both calcareous and siliceous skeletal components. Oil shales, in contrast, have more mineral matter than algal coals, with some of the inorganic matrix often being contributed by the algae themselves. Coals and oil shales should therefore be viewed merely as sedimentary rocks containing special types of kerogens in very high concentrations.

KEROGEN FORMATION The process of kerogen formation actually begins during senescence of organisms, when the chemical and biological destruction and transformation of organic tissues begin. Large organic biopolymers of highly regular structure (proteins and carbohydrates, for example) are partially or completely dismantled, and the individual component parts are either destroyed or used to construct new geopolymers, large molecules that have no regular or biologically defined structure. These geopolymers are the precursors for kerogen but are not yet true kerogens. The smallest of these geopolymers are usually called fulvic acids; slightly larger ones, humic acids; and still larger ones, humins. During the course of diagenesis in the water column, soils, and sediments, the geopolymers become larger, more complex, and less regular in structure. True kerogens, having very high molecular weights, develop after tens or hundreds of meters of burial.

The detailed chemistry of kerogen formation need not concern us greatly. Diagenesis results mainly in loss of water, carbon dioxide, and ammonia from the original geopolymers. If anaerobic sulfate

Kerogen - 18

reduction is occurring in the sediments, and if the sediments are depleted in heavy-metal ions (which is often the case in nonclastic sediments but is seldom true in shales), large amounts of sulfur may become incorporated into the kerogen structure. The amount of sulfur contributed by the original organic matter itself is very small. Carboncarbon double bonds, which are highly reactive, are converted into saturated or cyclic structures.

Kerogen formation competes with the destruction of organic matter by oxidative processes. Most organic oxidation in sedimentary environments is microbially mediated. Microorganisms prefer to attack small molecules that are biogenic, or at least look very much like biogenic molecules.

Geopolymers are more or less immune to bacterial degradation, because the bacterial enzyme systems do not know how to attack them. In an oxidizing environment many of the small biogenic molecules will be attacked by bacteria before they can form geopolymers. In a low-oxygen (reducing) environment, in contrast, the subdued level of bacterial activity allows more time for the formation of geopolymers and, therefore, better organic preservation.

Kerogens formed under reducing conditions will be composed of fragments of many kinds of biogenic molecules. Those kerogens formed under oxidizing conditions, in contrast, contain mainly the most resistant types of biogenic molecules that were ignored by microorganisms during diagenesis.

KEROGEN COMPOSITION Because each kerogen molecule is unique, it is somewhat fruitless to attempt a detailed discussion of the chemical composition of kerogens. Even if such a description were possible, it would not be of great and direct significance to exploration geologists. What is within our reach, and ultimately of much greater practical value, is developing a general method of describing gross kerogen composition and relating it to hydrocarbon-generative capacity. One way that we can begin is by classifying kerogens into a few general types.

About a decade ago workers at the French Petroleum Institute developed a useful scheme for describing kerogens that is still the standard today. They identified three main types of kerogen (called Types I, II, and III) and have studied the chemical characteristics and the nature of the organisms from which all types of kerogens were derived. Subsequent investigations have identified Type IV kerogen as well.

The four types of kerogen, the macerals that they are composed of, and their organic precursors

Transformation of organic material in sediments and sedimentary rocks.

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Type I kerogen is quite rare because it is derived principally from lacustrine algae. The best-known example is the Green River Shale, of middle Eocene age, from Wyoming, Utah, and Colorado.

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. Occurrences of Type I kerogens are limited to anoxic lakes and to a few unusual marine environments. Type I kerogens have high generative capacities for liquid hydrocarbons.

Type II kerogens arise from several very different sources, including marine algae, pollen and spores, leaf waxes, and fossil resin. They also include contributions from bacterial-cell lipids. The various Type II kerogens are grouped together, despite their very disparate origins, because they all have great capacities to generate liquid hydrocarbons. Most Type II kerogens are found in marine sediments deposited under reducing conditions.

Type III kerogens are composed of terrestrial organic material that is lacking in fatty or waxy components. Cellulose and lignin are major contributors. Type III kerogens have much lower hydrocarbon-generative capacities than do Type II kerogens and, unless they have small inclusions of Type II material, are normally considered to generate mainly gas.

Type IV kerogens contain mainly reworked organic debris and highly oxidized material of various origins. They are generally considered to have essentially no hydrocarbon-source potential.

Hydrogen contents of immature kerogens (expressed as atomic H/C ratios) correlate with kerogen type. In the immature state, Type I (algal) kerogens have the highest hydrogen contents because they have few rings or aromatic structures. Type II (liptinitic) kerogens are also high in hydrogen.

Type III (humic) kerogens, in contrast, have lower hydrogen contents because they contain extensive aromatic systems. Type IV kerogens, which mainly contain polycyclic aromatic systems, have the lowest hydrogen contents.

Heteroatom contents of kerogens also vary with kerogen type. Type IV kerogens are highly oxidized and therefore contain large amounts of oxygen. Type III kerogens have high oxygen contents because they are formed from lignin, cellulose, phenols, and carbohydrates. Type I and Type II kerogens, in contrast, contain far less oxygen because they were formed from oxygen-poor lipid materials.

Van Krevelen diagram showing maturation pathways for Types 1 to IV kerogens as traced by changes in atomic HIC and OIC ratios. The shaded areas approximately represent diagenesis, catagenesis, and metagenesis, successively.

Kerogen - 20

Sulfur and nitrogen contents of kerogens are also variable and, in some cases, interrelated. Nitrogen is derived mainly from proteinaceous material, which is destroyed rapidly during diagenesis. Most high-nitrogen kerogens were therefore deposited under anoxic conditions where diagenesis was severely limited. Because lignins and carbohydrates contain little nitrogen, most terrestrially influenced kerogens are low in nitrogen.

Kerogen sulfur, in contrast, is derived mainly from sulfate that was reduced by anaerobic bacteria.

High-sulfur kerogens (and coals) are almost always associated with marine deposition, because fresh waters are usually low in sulfate. Sulfur is only incorporated into kerogens in large quantities where sulfate reduction is extensive and where Fe +2 ions are absent (organic-rich, anoxic, marine, nonclastic sediments). Many high-sulfur kerogens are also high in nitrogen.

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. Kerogen types are defined by the morphologies of the kerogen particles. In many cases the original cellular structure is still recognizable, proving the origin of the particle. In others the original fabric has disappeared completely, forcing us to make assumptions about the source organisms. Microscopic organic analysis has reached a fairly high level of refinement and is often capable of assessing kerogen type with good accuracy.

The different types of kerogen particles are called macerals, a term taken trom coal petrology.

Macerals are essentially organic minerals; they are to kerogen what minerals are to a rock. The kerogen in a given sedimentary rock includes many individual particles that are often derived from a variety of sources. Thus few kerogens consist of a single maceral type.

Maceral names were developed by coal petrologists to describe, wherever possible, the materials from which a maceral was derived. A list of the most common macerals and their precursors is given in the table presented earlier in this chapter.

It is possible to make a reasonably good correlation between kerogen type based on chemical characteristics and kerogen type based on visual appearance. The correspondence is not perfect, however, because there is not a perfect biological separation of the various types of living organic matter. The biggest problem comes in identifying Type III kerogen. 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.

KEROGEN MATURATION INTRODUCTION Very important changes, called maturation, occur when a kerogen is subjected to high temperatures over long periods of time. Thermal decomposition reactions, called catagenesis and metagenesis, break off small molecules and leave behind a more resistant kerogen residue. The small molecules eventually become petroleum and natural gas.

By convention the term catagenesis usually refers to the stages of kerogen decomposition during which oil and wet gas are produced. Metagenesis, which occurs after catagenesis, represents drygas generation. Despite its name, metagenesis is not equivalent to "metamorphism." Metagenesis begins long before true rock metamorphism, but it also continues through the metamorphic stage.

Although the terms catagenesis and oil generation are often used synonymously, they are not precisely equivalent. Catagenesis and hydrocarbon generation occur concurrently, but they really represent different aspects of the same process. Catagenesis refers to transformations of kerogen molecules, whereas hydrocarbon generation focuses on the production of hydrocarbon molecules. In this text we shall use the terms somewhat interchangeably, especially when we are discussing both aspects simultaneously. In principle, however, they represent fundamentally different perspectives.

Kerogen - 21

This chapter will focus on those changes in the residual kerogen that accompany catagenesis. The composition of the products (bitumen, oil, and gas) will be discussed in a following chapter.

Kerogen maturation is not a reversible process-any more than baking a cake is reversible.

Furthermore, the chemical process of maturation never stops completely, even if drastic decreases in temperature occur. 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. For practical purposes, however, the rates of catagenesis are generally not important at temperatures below about 70째 C. Furthermore, in most cases decreases of temperature in excess of about 20째-30째 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.

It is impossible to set precise and universal temperature limits for catagenesis, because time also plays a role. Old rocks will often generate hydrocarbons at significantly lower temperatures than young rocks, simply because the longer time available compensates for lower temperatures. This complex interplay between the effects of time and temperature on maturity is discussed in a later chapter.

EFFECTS OF MATURATION ON KEROGENS Kerogen undergoes important and detectable changes during catagenesis and metagenesis. Some of these changes can be measured quantitatively, thus allowing us to judge the extent to which kerogen maturation has proceeded. The real reason for following kerogen catagenesis, of course, is to monitor hydrocarbon generation. Although it is obvious that many measurable changes in kerogens are related to hydrocarbon generation, it is also true that other changes in kerogen properties have little or nothing to do with it, and thus are not necessarily valid indicators of hydrocarbon generation. 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.

As we saw earlier, the cracking of any organic molecule requires hydrogen. The more hydrogen a kerogen contains, the more hydrocarbons it can yield during cracking. Because many of the light product molecules are rich in hydrogen, the residual kerogen gradually becomes more aromatic and hydrogen poor as catagenesis proceeds. 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, provided that the hydrogen content of the kerogen was known prior to the onset of catagenesis.

Nitrogen and sulfur are also lost from kerogens during catagenesis. Nitrogen loss occurs primarily during late catagenesis or metagenesis, after hydrogen loss is well advanced. In contrast, much of the sulfur is lost in the earliest stages of catagenesis, as evidenced by low maturity, high-sulfur oils found in a number of areas, including the Miocene Monterey Formation of southern California.

The most important implication of these chemical changes is that the remaining hydrocarbongenerative capacity of a kerogen decreases during catagenesis and metagenesis. All kerogens become increasingly aromatic and depleted in hydrogen and oxygen during thermal maturation. In the late stages of maturity, Types I, II, and III kerogens will therefore be very similar chemically, possessing essentially no remaining hydrocarbon generative capacity.

Kerogen particles become darker during catagenesis and metagenesis, much as a cookie browns during baking. There is a steady color progression yellow-goldenorange-light brown-dark brownblack as a result of polymerization and aromatization reactions. These reactions are intimately related to important changes in the chemical structure of kerogen, but they are not necessarily identical with hydrocarbon generation. There is therefore no necessary cause-and-effect relationship

Kerogen - 22

between kerogen darkening and hydrocarbon generation, and no guarantee that a particular kerogen color always heralds the onset of oil generation.

As kerogen matures and becomes more aromatic, its structure becomes more ordered, because the flat aromatic sheets can stack neatly. These structural reorganizations bring about changes in physical properties of kerogens. One property that is strongly affected, and which can be used to gauge the extent of molecular reorganization, is the ability of kerogen particles to reflect incident light coherently. The more random a kerogen's structure, the more an incident light beam will be scattered, and the less it will be reflected.

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, and because vitrinite particles also occur in kerogens, the technique, called vitrinite reflectance, has been widely and successfully applied in assessing kerogen maturity.

Cracking often produces free radicals, which are unpaired electrons not yet involved in chemical honds. Kerogens, especially highly aromatic ones, contain large numbers of unpaired electrons. The concentration of free radicals in a given kerogen has been found to increase with increasing maturity. Free-radical concentrations can be measured by electron-spin resonance.

Kerogens often fluoresce when irradiated. The intensity and wavelength of the fluorescente are functions of kerogen maturity.

Some properties of kerogen change very little during catagenesis. For example, carbon-isotopic compositions of kerogens are affected little by maturation. 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, somewhat beyond the oil-generation window.

Plot of bitumen generation as a function of maturity (dashed fine) compared to bitumen remaining in rock (solid line). The difference between the two curves represents bitumen expelled from the rock or cracked to light hydrocarbons.

HYDROCARBON GENERATION As kerogen catagenesis occurs, small molecules are broken off the kerogen matrix. Some of these are hydrocarbons, while others are small heterocompounds. These small compounds are much more mobile than the kerogen molecules and are the direct precursors of oil and gas. A general name tor these molecules is bitumen.

Bitumen generation occurs mainly during catagenesis; during metagenesis the chief product is methane. If neither expulsion from the source rock nor cracking of bitumen occurred, there would be a large and continuous build-up of bitumen in the rock as a result of catagenetic decomposition of kerogen. What actually occurs, however, is that some of the bitumen is expelled from the source rock or cracked to gas, resulting in lower bitumen contents in the source. Both curves are highly

Kerogen - 23

idealized, however, because natural variations among samples cause much scatter in experimental data.

It has become apparent in recent years that not all kerogens generate hydrocarbons at the same catagenetic levels, as measured by parameters such as vitrinite reflectance. Given the significant chemical differences among the various types of kerogens, this result is hardly surprising.

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. Resinite consists of polymerized terpanes (ten-carbon isoprenoids) that can decompose easily by reversing the polymerization process. Sulfur-rich kerogens decompose easily because carbon-sulfur hbonds are weaker than any bonds in sulfur-poor kerogens.

Effective generation of hydrocarbons requires that the generated products be expelled from the source-rock matrix and migrated to a trap. Timing and efficiency of expulsion depend on a number of factors, including rock physics and organic-geochemical considerations. We shall consider the latter briefly here.

Many workers now believe that microfracturing of source rocks is very important tor hydrocarbon expulsion. Microfracturing is related to overpressuring, which in turn is partly attributed to hydrocarbon generation itself. Rich rocks will become overpressured earlier than lean ones and thus will also expel hydrocarbons earlier. In very lean rocks expulsion may occur so late that cracking of the generated bitumen is competitive with expulsion. In such cases the expelled products will be mainly gas.

SUMMARY Kerogen begins to form during early diagenesis, when large geopolymers are created from biological molecules. The chemical composition and morphology of kerogen macerals depend both on the type of original organic matter and on diagenetic transformations. Numerous methods exist for tracing the history of a kerogen and determining its original chemical and physical characteristics.

Catagenesis of kerogen produces a more aromatic, hydrogen-poor, residual kerogen as well as small molecules that are the direct precursors for petroleum and natural gas. Several methods exist for estimating the extent to which hydrocarbon generation has occurred in a given kerogen, but none of these measurements is closely linked to the actual process of hydrocarbon generation.

Thus, although we know that oil generation does occur during the phase we call catagenesis, we cannot always define the limits of hydrocarbon generation with great confidence.

The chemical composition of a kerogen controls the timing of hydrocarbon generation and the type of products obtained. Kerogens formed from lipid-rich organic material are likely to generate liquid hydrocarbons, whereas those kerogens that contain few lipids will generate mainly gas. Kerogens formed from resinite will generate condensates or light oils quite early. High-sulfur kerogens generate heavy, high-sulfur oils at low levels of maturity. Other kerogens usually follow a more traditional model.

Source rocks that generate large amounts of hydrocarbons early are likely to expel those hydrocarbons early. Candidates for early expulsion would be very organic rich rocks and those containing resinite or high-sulfur kerogens. Conversely, those rocks that generate few hydrocarbons may not expel them until they have been cracked to gas.

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Bitumen, Petroleum, and Natural Gas -

5 - Bitumen, Petroleum, and Natural Gas INTRODUCTION Petroleum obtained from reservoir rocks and bitumen extracted from fine-grained rocks have many similarities, but they also exhibit many important differences. There is no doubt that they are related; indeed, bitumen is almost universally accepted as the direct precursor for petroleum.

However, many unanswered questions remain about the processes that transform bitumen into petroleum. Major compositional changes occur in going from bitumen to petroleum, but we are not certain whether they occur mainly within the source rock or during migration through the reservoir rock. We also do not know how much of the change involves chemical reactions, 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.

Both bitumens and petroleums exhibit a wide range of compositions. Much of this variety is related to source-rock facies and the composition of the kerogens that generated the bitumens. Maturity also exerts control over bitumen and petroleum composition. Reservoir transformations in some cases greatly affect oil composition and properties.

Bitumen and petroleum compositions can also be used as tools in correlating samples with each other. Such correlations can be particularly useful in establishing genetic relationships among samples. In order to understand bitumen and petroleum compositions and to use them for exploration, however, 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. This chapter will compare and contrast bitumen and petroleum compositions and examine the factors responsible for the observed differences.

COMPOUNDS PRESENT IN BITUMEN AND PETROLEUM GENERAL CLASSES OF COMPOUNDS Both bitumen and petroleum contain a very large number of different chemical compounds. Some of these are present in relatively large quantities, while others are only trace contributors. In order to investigate the individual compounds present, we first separate a crude oil or a bitumen into several fractions having distinct properties.

Each of the fractions contains certain types of chemical compounds. One fraction consists mainly of saturated hydrocarbons; n-alkanes, branched hydrocarbons (including isoprenoids), and cyclics.

Saturated hydrocarbons are the most thoroughly studied of the components of petroleum and bitumen because they are the easiest to work with analytically.

A second fraction consists of aromatic hydrocarbons and some light sulfur-containing compounds.

Light aromatic hydrocarbons, like benzene and toluene, have been studied in petroleums, but these compounds are lost from bitumens during evaporation of the solvent used in extracting the bitumen from the rock. Heavier aromatic and naphthenoaromatic hydrocarbons, particularly those derived from diterpanes, triterpanes, and steranes, are more commonly studied.

Most of the NSO compounds appear in the remaining two fractions. The lighter of these fractions, variously called polars, NSOs, and resins, contains a wide variety of small and medium-sized molecules with one or more heteroatoms. Few of these heterocompounds have been studied carefully.

The final fraction contains very large, highly aromatic asphaltene molecules that are often rich in heteroatoms. Asphaltenes tend to aggregate into stacks because of their planarity, and form complexes with molecular weights of perhaps 50,000. The large sizes of asphaltene units render

Bitumen, Petroleum, and Natural Gas - 25

them insoluble in light solvents. Asphaltenes can thus be removed from oils or bitumens in the laboratory or refinery by adding a light hydrocarbon, such as pentane or propane. Because of their molecular complexity and heterogeneity, asphaltene molecules have not been studied in detail.

SPECIFIC COMPOUNDS Biomarkers. Many of the compounds and classes of compounds that we find in crude oils and bitumens are called biomarkers, an abbreviation for biological markers. These compounds, which are derived from biogenic precursor molecules, are essentially molecular fossils. The most useful biomarkers serve as indicators of the organisms from which the bitumen or petroleum was derived, or of the diagenetic conditions under which the organic matter was buried. In a few cases specific precursor organisms or molecules can be identified, whereas in other instances we may be able to limit the possible precursors to only a few species. In most cases, however, although we know for certain that the biomarker molecule is biogenic, we are unable to use it as an "index fossil" for specific organisms.

Other compounds. 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. They are, however, of biological origin, but their sources are simply no longer recognizable due to diagenetic and catagenetic transformations.

FACTORS AFFECTING COMPOSITION OF BITUMEN AND PETROLEUM SOURCE AND DIAGENESIS Biomarkers n-Alkanes were among the first biomarkers to be studied extensively. Their high concentration in bitumens and oils is best explained by their existence in plant and algal lipids, and by their catagenetic formation from long-chain compounds such as fatty acids and alcohols.

Another important indication of the origin of n-alkanes is the distribution of individual homologs, or members of the n-alkane series. For the most part n-alkanes present in terrestrial plants have odd numbers of carbon atoms, especially 23, 25, 27, 29, and 31 atoms.

In contrast, marine algae produce n-alkanes that have a maximum in their distribution at C-17 or C22, depending upon the species present. The distributions are quite sharp, and no preference for either odd- or even-carbon homologs is evident.

Many sediments, of course, receive contributions of n-alkanes from both terrestrial and marine sources. Their n-alkane distributions reflect this mix.

Sediments are also known that exhibit a strong preference for n-alkanes having an even number of carbon atoms. These n-alkanes are believed to be formed by hydrogenation (reduction) of longchain fatty acids and alcohols having even numbers of carbon atoms. (Among the acids and alcohols present in living organisms, even-carbon homologs predominate as strongly as do the oddcarbon homologs among the n-alkanes.) Even-carbon preferences occur principally in evaporitic and carbonate sediments, where input of terrestrial n-alkanes is minimal and diagenetic conditions are highly reducing.

Carbon Preference Index, or CPI, 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).

The average of two ranges is taken to minimize bias produced by the generally decreasing n-alkane concentrations with increasing number of carbon atoms. If the number of odd- and even-carbon members is equal, the CPI is 1.0. If odd-carbon homologs predominate, the CPI is greater than 1.0.

However, because the concentration of n-alkanes often decreases with increasing carbon number, the lower-carbon homologs are given more weight in the calculation. CPI values can therefore

26

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.

RESERVOIR TRANSFORMATIONS 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 90째 C, regardless of the length of time they spend there. On the other hand, a reservoir above 120째 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.

COMPARISON OF BITUMEN AND PETROLEUM 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.

28

Bitumen, Petroleum, and Natural Gas -

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.

SUMMARY 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.

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6 - Migration DEFINITIONS Migration is the movement of oil and gas within the subsurface. Primary migration is the first phase of the migration process; it involves expulsion of hydrocarbons from their fine-grained, lowpermeability source rock into a carrier bed having much greater permeability. Secondary migration is the movement of oil and gas within this carrier bed. Accumulation is the concentration of migrated hydrocarbons in a relatively immobile configuration, where they can be preserved over long periods of time. Traps are the means by which migration is stopped and accumulation occurs.

Each of these steps is quite distinct from the others. In order to understand the complex sequence of events that we call migration, we must look at each of these steps separately. This chapter wi11 not go into the physics and chemistry of migration in detail, but will describe the most widely held views on the dominant mechanisms of primary and secondary migration and accumulation.

PRIMARY MIGRATION MECHANISMS Many theories about primary migration (expulsion) have been popular at various times, but those that have been discounted will not be discussed here. Today there are only three mechanisms of primary migration that are given serious consideration by most petroleum geochemists: diffusion, oil-phase expulsion, and solution in gas.

Diffusion has been shown to be active on at least a minor scale and over short distances in carefully studied cores. Its importance is probably limited to the edges of thick units or to thin source beds.

Furthermore, it is probably most effective in immature rocks, where pre-existing light hydrocarbons bleed out of the rocks prior to the onset of significant generation and expulsion.

The main problem with diffusion as an important mechanism of migration is that diffusion is by definition a dispersive force, whereas accumulation of hydrocarbons requires concentration.

Diffusion would therefore have to be coupled with a powerful concentrating force to yield accumulations of appreciable size. During intense hydrocarbon generation, 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. There appear to be three distinct ways in which oilphase expulsion can occur. One occurs most commonly as a result of microfracturing induced by overpressuring during hydrocarbon generation. When the internal pressures exceed the strength of the rock, microfracturing occurs, particularly along lines of weakness such as bedding planes.

Laminated source rocks may therefore expel hydrocarbons with greater efficiency than massive rocks. Once the internal pressure has returned to normal, the microfractures heal. The hydrocarbons within the pores then become isolated again because of the impermeability of the waterwet source rocks to hydrocarbons, and overpressuring commences anew. Many cycles of pressure buildup, microfracturing, expulsion, and pressure release can be repeated.

An important implication of the microfracturing model is that expulsion cannot take place until the strength of the source rock has been exceeded. Based on empirical evidence, 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. Although the exact threshold value must vary considerably as a function of rock lithology and other factors, Momper's value has been widely accepted as a reasonable average.

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Once the threshold has been exceeded, most of the hydrocarbons are expelled, but a large proportion of NSO compounds and heavier hydrocarbons are left behind. Thus inefficiency of expulsion is responsible for much of the difference in composition of bitumen and petroleum that we noted earlier. Primary migration is unquestionably the most difficult part of the entire migration process. Therefore the threshold must represent not only a hurdle to be cleared by the bitumen before it can leave the source rock, but also an "exit tax."

We can only estimate the fraction of the bitumen left in the source rock during microfractureinduced expulsion. By comparing the average hydrocarbon compositions of bitumen and crude oil, and assuming that expulsion of hydrocarbons is ten times as efficient as expulsion of NSO compounds, we can estimate that once the expulsion threshold is reached the expulsion efficiency for bitumen is about 50%. Of course, this approach is rather approximate, but it does give some idea of the efficiency of expulsion.

A second way in which oil-phase expulsion can occur is from very organic-rich rocks prior to the onset of strong hydrocarbon generation. This expulsion process probably releases internal pressures in the rock, but the mechanism by which overpressuring is achieved is not understood. The organic matter expelled consists mainly of lipids that were present in the sediment during deposition and diagenesis. Therefore, this early expulsion mechanism seems to be limited to rocks having very high original contents of lipids.

Finally, oil-phase expulsion can take place when bitumen forms a continuous network that replaces water as the wetting agent in the source rock. Expulsion of hydrocarbons is facilitated because water-mineral and water-water interactions no longer need be overcome. This type of expulsion is probably only operative in very rich source rocks during the main phase of oil generation.

The third mechanism, expulsion of oil dissolved in gas, requires that there be a separate gas phase.

Such a phase could only exist where the amount of gas far exceeds the amount of liquid hydrocarbons; therefore, it would be expected only in the late stages of catagenesis or in source rocks capable of generating mainly gas. Because neither case is of great general significance for petroleum formation, we conclude that solution in gas is a minor mechanism for oil expulsion.

DISTANCE AND DIRECTION The distances traversed by hydrocarbons during primary migration are short. Primary migration is difficult and slow, because petroleum is being forced through rocks having low matrix permeabilities. As soon as easier paths become available, the migrating fluids will take them. Thus primary migration ends whenever a permeable conduit for secondary migration is reached.

In most cases the distances of primary migration are probably between 10 centimetres and 100 m.

Sand stringers within shale units can provide secondary migration conduits for hydrocarbons sourced in the shales. Fracture and joint systems, particularly in brittle carbonate and opal-chert source rocks, also make excellent secondary-migration pathways. Massive, unfractured source-rock units are relatively rare; where they do exist, primary migration may be of poor efficiency. In most cases hydrocarbons are generated within short distances of viable secondary-migration conduits.

Because the driving force for microfracture-induced primary migration is pressure release, hydrocarbons will be expelled in any direction that offers a lower pressure than that in the source rock. Because the source rock is overpressured, expulsion can be lateral, upward, or downward, depending upon the carrier-bed characteristics of the surrounding rocks. Thus a source rock lying between two sands will expel hydrocarbons into both carrier beds.

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SECONDARY MIGRATION MECHANISM Once hydrocarbons are expelled from the source rock in a separate hydrocarbon phase into a secondary-migration conduit, subsequent movement of the hydrocarbons will be driven by buoyancy. Hydrocarbons are almost all less dense than formation waters, and therefore are more buoyant. Hydrocarbons are thus capable of displacing water downward and moving upward themselves. 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. Coalescence of globules of hydrocarbons after expulsion from the source rock therefore increases their ability to move upward through water-wet rocks.

Retardatin of buoyant movement as an oil globule (X) is deformed to fit in to a narrow pore throat (Y). The upward buoyant force is partly or completely opposed by the capillary-entry pressure, the force required to deform the oil globule enough to enter the pore throat.

If the capillary-entry pressure exceeds the buoyant force, secondary migration will cease until either the capillary-entry pressure is reduced or the buoyant force is increased.

Opposing the buoyancy is capillary-entry pressure, which is resistance to entry of the hydrocarbon globule or stringer into pore throats. Whenever a pore throat narrower than the globule is encountered, the globule must deform to squeeze into the pore. The smaller the pore throat, the more deformation is required. If the upward force of buoyancy is large enough, the globule will squeeze into the pore throat and continue moving upward. If, however, the pore throat is very tiny or if the buoyant force is small, the globule cannot enter, and becomes stuck until either the buoyant force or the capillary entry pressure changes. When hydrocarbons cease moving, we say that accumulation has occurred.

This model is very simple, requiring only the existence of two forces. Buoyancy promotes migration, whereas capillary-entry pressure retards or stops it. A third force-namely, hydrodynamic flow, can modify hydrocarbon movement, but it is not essential and does not change our basic model. If water is flowing in the subsurface in the same direction as hydrocarbons are moving by buoyancy, then the rate of hydrocarbon movement should be enhanced somewhat. In contrast, if bulk water movement opposes the direction of buoyant movement, then the rate of hydrocarbon transport will be retarded.

These modifications to the overall scheme are probably minor.

DISTANCE AND DIRECTION Secondary migration occurs preferentially in the direction that offers the greatest buoyant advantage. Thus movement within a confined migration conduit will be updip perpendicular to structural contours whenever possible. Where faulting or facies changes create impassable barriers (capillary-entry pressure exceeds buoyant force), migration may have to proceed at an oblique angle to structural contours.

Within massive sandstone, secondary migration will occur both laterally and vertically. That is, hydrocarbons entering the land from an underlying source rock will move toward the top of the sand even as they migrate laterally updip. This fact has important implications for tracing migration pathways through a thick conduit. Structural contours on the top of the carrier bed will

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in general be more useful than contours on its base, 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).

Vertical migration can also occur across formations. Stacked sands in a paleodelta, for example, can offer possible pathways (although sometimes rather tortuous ones) for vertical migration.

Unconformities also can juxtapose migration conduits, thus providing a potentially very effective system for combined vertical and lateral migration. Faults may play an important role in vertical migration, not only because they often juxtapose carrier beds from different stratigraphic horizons, but also because an active fault or the brecciated zone adjacent to a fault may itself have high permeability.

The question of long-distance migration has been much discussed and disputed. There is no a priori reason why secondary migration cannot be a very-long-distance phenomenon. Indeed, the largest hydrocarbon deposits known, including the Athabasca Tar Sands of western Canada, the heavy oils in the Orinoco Belt of Venezuela, and the Saudi Arabian crude oils, all must have migrated long distances; otherwise it is impossible to account for the incredible volumes of hydrocarbons in place today.

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, and has provided as carrier beds continuous blankets of sand juxtaposed with these source rocks. The absence of both tectonic and stratigraphic barriers permits long-distance migration.

Most basins, however, are broken up tectonically and have poor lateral continuity of carrier beds, as a result of both tectonic disruption and facies changes related to tectonic events. Lateral migration is therefore often stymied, leading to smaller fault-bounded accumulations and vertical migration.

Drainage area is one of the most important factors influencing the size of hydrocarbon accumulations. Long-distance migration implies, by definition, large drainage areas and chances for very large accumulations. Lack of long-distance migration opportunities implies that supergiant and giant accumulations are far less likely and that exploration targets will be smaller.

It is possible to have lateral migrations of as much as a few hundred kilometers in exceptional circumstances. Much more common, however, are basins in which lateral migration distances do not exceed a few tens of kilometers. Vertical migration distances can also be considerable, although it should be remembered that there are two fundamentally different types of vertical migration.

Migration updip within a single stratum can accomplish a large amount of "vertical" migration rather painlessly. Vertical migration across stratigraphic boundaries is more difficult. Nevertheless, distances of several thousand feet are not unheard of.

ACCUMULATION INTRODUCTION In the old days, when migration was thought to occur mainly in water solution, the process of hydrocarbon accumulation was somewhat mystical. Hydrocarbons had to remain in solution until they reached the trap, at which time they suddenly became immiscible with the water and formed a separate hydrocarbon phase. Various mechanisms for exsolution were proposed to explain how all this was supposed to happen.

Today we believe that hydrocarbons migrate as a separate phase. This model greatly simplifies the problem of accumulation, because now accumulation can occur where the buoyancy-driven movement of the hydrocarbon phase is stopped or even strongly impeded. Cap rocks having low

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permeabilities to hydrocarbons provide barriers to migration: that is, rocks whose capillary-entry pressures are high enough to overcome hydrocarbon buoyancy.

Cross section across the Rhine Graben of West Germany showing the discontinuity of strata as a result of extensional tectonism endemic to rift basins. Lateral migration is of necessity short distance, and vertical migration becomes important. Accumulations are small because drainage areas are small.

CLASSICAL TRAPS. Most hydrocarbon traps are either structural or stratigraphic. The seal prevents vertical migration from the reservoir rock into overlying strata, while the structure or lithologic change prevents lateral updip migration. Classical traps are well understood, and will be covered separately.

KINETIC TRAPS Kinetic traps represent a fundamentally new concept in trapping mechanisms for hydrocarbons. The simple principle behind a kinetic trap is that hydrocarbons are supplied to the trap faster than they can leak away. Seals in the traditional sense of the word may not exist. This model requires, of course, that strong hydrocarbon generation and migration is going on today. The Elmworth Field in the Alberta Deep Basin of Canada is the prototype for kinetic gas accumulations. 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. The low permeability sand thus creates a bottleneck to gas migration. Because gas generation is very rapid, the low-permeability sands become filled with gas. Gas production is actually from the low-permeability sand rather than from the high-permeability sand updip and downdip. No traditional seal exists. Because the high permeability sand updip allows gas to migrate rapidly through, it remains water wet. Thus the Elmworth Field exhibits a water-over-gas contact.

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. Fracturing associated with high races of oil generation in the Green River Shale has created a supergiant accumulation at Altamont.

The much smaller Antelope Field produces from the Mississippian Bakken Formation, a fractured shale that is both source and reservoir. Much of the hydrocarbon storage at Antelope is apparently in silts and sands juxtaposed with the producible Bakken reservoir.

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Many of the accumulations in Pliocene reservoirs in southern California are also kinetic accumulations in a slightly different sense. Cap-rocks in those fields are often poor, and would be incapable of sealing accumulations for long geologic periods. Because intense oil generation is going on now, however, large accumulations have formed despite high rates of leakage.

TAR-MAT TRAPS Tar mats produced by biodegradation can create excellent seals. In cases where no other structural or stratigraphic trapping mechanism exists, tar mats may provide the only possible means for retaining any hydrocarbons. Accumulations beneath tar-mat seals are generally biodegraded themselves, because the same conditions that created the tar mat persist in the subsurface. Despite the rarity of tar-mat seals, and the poor producibilitv of the hydrocarbons they trap, 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.

GAS HYDRATES Formation of crystalline hydrates of natural gas provides an extremely efficient trapping mechanism for natural gas, especially methane. 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, and in zones of permafrost. The base of the gas hydrate zone forms a pronounced seismic reflector that often simulates bottom contours and cuts across bedding planes. These gas hydrates consist of a rigid lattice of water molecules that form a cage within which a single molecule of gas is trapped. Methane is by far the most commonly trapped gas molecule, but hydrates large enough to accommodate butane molecules are known.

One important feature of methane hydrates is that they are much more efficient at storing methane than is liquid pore water. Because hydrate zones are often hundreds of meters thick, the quantities of gas in such accumulations are huge.

A second characteristic is that gas hydrates form effective seals against vertical hydrocarbon migration. Formation of hydrates thus provides an important trapping mechanism, because much of the methane trapped is biogenic and was formed in young, unconsolidated sediments that would have no other means of retaining the methane.

At the present time the vast potential of gas-hydrate accumulations is just beginning to be recognized. The technology necessary for producing these hydrocarbons has not yet been developed, but in the future gas-hydrate accumulations may be of great economic significance.

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. The polar (NSO) compounds interact most strongly with both mineral surfaces and water molecules, and thus are not expelled as efficiently with the oil phase. Once expulsion has occurred, there may be a chromatographic effect during secondary migration. The polar molecules once again interact most strongly with interstitial water and mineral surfaces, and thus get left behind as the oil globule or stringer moves upward.

Phase changes occur as a result of decreases in pressure and temperature during migration. When the original hydrocarbon phase contains large amounts of light components, these changes in temperature and pressure can cause separation of the original phase into a liquid phase and a gas phase. The gas phase will, of course, contain mainly light components, but it may also include some heavier hydrocarbons dissolved in the gas. As soon as two immiscible phases are formed, the lighter (gas) phase will be far more buoyant than the liquid phase. It will therefore migrate much faster and

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will also assume the structurally high position in any reservoirs containing both phases. When separation of a single hydrocarbon phase into two phases occurs, both new phases will have compositions that differ drastically from the original phase. 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. Polar compounds interact more strongly with water and rock minerals and thus move more slowly than hydrocarbons.

SIGNIFICANCE FOR EXPLORATION Explorationists who are reading about migration will surely ask, "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 efficiency of expulsion, and the timing of expulsion. We have already stated that oil is expelled primarily as a liquid phase; gas is presumably expelled as a gas phase. 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, leading to an enrichment of hydrocarbons in the expelled liquid.

Timing of expulsion must be dealt with in a different way. We already know two important facts about timing from our previous discussion: expulsion based on microfracturing cannot occur before generation, and expulsion occurs concurrently with generation to relieve generation-induced overpressuring. Thus if we can determine the timing of generation, we will also have determined the timing of expulsion.

In using our understanding of secondary migration for exploration, we want to determine the main pathways and conduite through which migration occurs, the barriers that modify die direction of migration and eventually stop it, and the vertical and horizontal distances involved. Proximity to effective source rocks and their permeabilities to hydrocarbons determine conduits. Pathways, as we have seen, are determined by structural contours on the top of the carrier beds. Barriers can be created by folding, by faulting, by decreases in permeability as a result of facies changes, or by the presence of tars. Vertical-migration distances can be considerable, depending upon stacking of reservoirs, vertical faulting, and the possibilities of combined vertical and lateral migration. Lateralmigration distances are strongly influenced by tectonic and depositional histories of basins.

Tectonically stable basins have the best potential for long-distance migration and supergiant accumulations. Unstable basins seldom have depositional or tectonic continuities necessary for longdistance lateral migration to occur.

In summary, as explorationists we have very pragmatic interests in migration. We need to know when hydrocarbons moved, in what direction they moved, and how far they moved.

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7 - Petroleum Traps We have seen petroleum generated in and expelled from the source rock formation into an overlying or underlying reservoir. If it can, it will escape to surface as a seepage, where it is lost. If then we are to find any of it still preserved, 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), but there must also be some sort of blockage to prevent further migration. This may be caused either by the reservoir itself dying out or by an interruption of its upwards continuity to the surface. Such a configuration of the reservoir is known as a trap. Any oil getting there will be unable to migrate further and so it starts to accumulate, by displacing the water already there in the porosity.

The location of a trap in the subsurface is often the first objective of an exploration program. Indeed, before we reached our modern understanding of the geology of petroleum, exploration used to consist largely of finding a trap, drilling a well into it, and hoping for the best. Nowadays we can do better, 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 REPRESENTATION OF TRAPS Traps are commonly depicted in two ways. First, they can be mapped by means of contours drawn on the top of the reservoir formation. A structure contour map resembles an ordinary topographic contour map, except that the contours are in depth below sealevel, so that the highest points on the map have the lowest values. Faults will be marked by jumps of the contours, as the beds on one side are dropped down relative to the other.

To complement the structure contour map, one or more cross-sections may be drawn. To give a true representation, they should properly be drawn with the same scale for both the vertical and the horizontal, but it is often convenient to exaggerate the vertical to show the individual beds more clearly.

Note that we commonly highlight petroleum accumulations by shading or colouring the reservoir formations where they contain oil or gas, which may give a misleading impression of `lakes' of

petroleum under the ground!

Structure contour maps. The top of a reservoir formation, is mapped by contours showing depth below sealevel. (a) A simple hypothetical anticline. (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; the ticks are on the downthrown sides of the faults. The contours are in feet below mean sea-level.(2-18)

Before we go further, we need a few definitions. These are illustrated using a simple anticline as an example. The highest point of the reservoir, up towards the ground surface, is known as the crest of the trap. The lowest point, which may refer either to its depth or to the spot under the ground where it lies, is the spill-point: this is where oil, if more continues to migrate up into the trap than can be

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accommodated, will spill out (under) and migrate on. The vertical height between the spill-point and the crest is referred to as the closure, and the same term is used loosely to refer to the area of the trap above the level of the spill-point.

Oil being lighter than water, separates out on top within the pore-spaces of the reservoir, so that we can recognize a generally horizontal oil-water contact. Similarly gas, being lighter still, will occur as a gas cap above a gas-oil contact. If there is no oil, then we may see a gas-water contact.

A single accumulation of oil or gas is called a pool. Where there is more than one such pool in the same or overlapping areas, perhaps if more than one reservoir is present, they are embraced by the familiar terms oilfield or gasfield.

Just a couple more terms. The vertical height of the oil (or gas) between the crest of the trap and the water contact is the oil- (or gas-) column. When referring to a single well, the informal term pay is often used. Let us remember, however, that most reservoir formations include some tight intervals, i.e. which have porosities and permeabilities too low for them to contribute oil to production. 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.

Some terms used to define a trap, using a cross-section of a simple anticline as example (2-19).

Now we can start to consider the types of trap whose discovery may await us. They are normally classified under four headings (2-21):

1. Structural, where the trap has been produced by deformation of the beds after they were deposited, either by folding or faulting.

2. Stratigraphic, in which the trap is formed by changes in the nature of the rocks themselves, or in their layering, the only structural effect being a tilt to allow the oil to migrate through the reservoir.

3. Combination traps, formed partly by structural and partly by stratigraphic effects, but not entirely due to either.

4. Hydrodynamic traps, which are rare and are mentioned mainly for completeness. The trap is due to water flowing through the reservoir and holding the oil in places where it would not otherwise be trapped.

STRUCTURAL TRAPS The best known type of trap is the anticline: on reaching the crest, petroleum migrating up along a reservoir can go no further and it accumulates there as a pool. However, there are various types of

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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. Traps can also be formed against faults if a chopped-off reservoir is thrown against a shale or other impervious rock.

The general principles of this are straightforward. We will describe in a little detail the most important types of anticline, noting the differences in shape and prospectivity that we have to try to interpret.

Anticlines. These compressive structures pose one problem right from the start. If, in cross-section, the anticline is asymmetrical, with one flank steeper than the other, then the position of the crest will shift with increasing depth; therefore in order to drill into a reservoir near its highest point (where we would expect the oil to be), we have to know its depth to know where best to locate the well. Seismic may help, but we commonly have to undertake some form of geometrical construction to interpret what is happening at depth. This leads us into the next problem.

Compressive structures have a range of shapes between the purely concentric or parallel anticline and the similar fold, depending on the nature and strength of the rock layers being folded. Let us see what the implications are for exploration.

Cross-sections of trap-forming anticlines. (a) The dips are the same on both flanks and the crest is beneath the same locality at all depths. (b) The anticline is asymmetrical and the crest shifts with increasing depth.

To test the crest at depth, a well would have to be located off-crest at surface.(2-22)

In the concentric fold the tops and bottoms of all the layers remain strictly parallel to each other, so that the beds maintain a constant thickness throughout. These conditions mean that the anticline becomes smaller and tighter at deeper levels until we reach a common `centre of curvature'. Below this point we have just too much rock to fit into the anticline, so that the beds become intensely crushed and thrust together: we may no longer even have an anticline at all. In this type of structure, we can thus expect to find only smaller and smaller accumulations of petroleum down to the centre of curvature, beyond which there may be no trap left to explore as the consequence of decoupling of layers. There is a definite limit to the depths to which we should drill.

The similar anticline, on the other hand, maintains its shape constant down to depth. This can only happen if there is an apparent thickening of some beds over the crest of the fold. In this case, we can find the trap present at all levels down to the basement, and we may be able to continue exploration down to depths where we have to stop for other reasons. This is a very different kettle of fish from the concentric anticline. In practice, many structures have forms in-between the two extremes, but an understanding of the shape and size of a prospect is clearly critical to programming an exploration well.

Other types of anticline can be formed without any lateral compression at all: an important one is the drape or drape-compaction structure. 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, and the blanket bulges upwards with an anticlinal shape. Cover it with a few more blankets and a duvet or two, and we may no longer be able to see where the bottle is.

Petroleum Traps - 39

A drape-compaction anticline, the beds being draped over an upfaulted block (horst) of basement rocks. Note that the anticline dies out upwards towards the surface.(2-25)

Similarly, if the first sediments in a basin were deposited over a hilly surface, or over an upfaulted block or horst, then they will blanket the hill as an anticline; higher beds will gradually mute and suppress the structure until it is no longer present at shallow levels. A second effect comes into play here: because there is a greater thickness of beds off the structure than over the top, 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. This compaction enhances the anticline formed by the drape; it is not always easy to separate out the two effects, and hence the combined name. In case anyone should think that this is unimportant, note that the largest oilfield in the world, Ghawar in Saudi Arabia, which contains more than four times as much oil as the whole of the North Sea put together, is in one such trap. Another is the Forties field in the North Sea, where the beds are draped over the eroded stumps of an old Jurassic volcano.

The effect of salt diapirism will be initially to bulge up the overlying sediments as an anticline, a salt pillow or a salt dome, and then to burst through them in the form of a salt plug or salt wall; it may extend up to the surface of the ground or only part way if the supply of salt is limited.

Diagrammatic section through two salt plugs, showing the variety of traps that may be associated with them. Note also that salt, being plastic, can be a perfect seal to any underlying accumulations.(2-26)

A wide variety of traps can be associated with salt plugs. Not only may an anticline be pushed up over the plug, it is also liable to fracture the overlying and surrounding beds creating fault traps; it may bend up and seal off the strata it cuts through, and finally a residual bulge may be left between two nearby plugs: a turtle or turtle-back structure. All of these possible traps may contain hydrocarbons. Extensive salt deposits and plugs with associated traps occur in many parts of the world: the southern North Sea and northern Germany; the Gulf Coast of the USA; the Canadian Arctic Islands; much of the west coast and continental shelf of Africa; the Middle East; and several others.

The last type of anticline that we should be aware of is the roll-over anticline. This occurs alongside a normal fault that is curved, so that it is steep near the surface and flattens with depth. In effect the downthrown side is being pulled away from the upthrown side which would tend to create an open fissure along the fault. Nature, however, does not like empty holes, and the beds on the downthrown side above the curving fault collapse to fill the gap, bending downwards into the hole. This creates a rollover anticline. Note a characteristic of these anticlines: not only do they `grow' with depth, but also

Petroleum Traps - 40

they are asymmetrical; at deeper levels the crest will shift away from the position of the fault at surface.

Again, therefore, we have to know whereabouts in the succession our prospective reservoir lies, and its depth, to locate an exploration well in the right place.

Roll-over anticlines: (A) a simple roll-over into a normal fault; (B) a roll-over complicated by subsidiary faulting near the crest. Note that, in both cases, the position of the crest is displaced with depth and that accumulations in successive reservoirs will not underlie the same surface position.

(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, or slumping as a sort of land-slide, down towards the deep ocean. Much of the oil under the Niger and Mississippi Deltas is in such roll-over anticlines.

Fault traps We indicated above that a trap may be formed where a dipping reservoir is cut off up-dip by a fault, setting it against something impermeable. The proviso is that we also have lateral closure: this may be provided by further faulting, or by opposing dips. The large Wytch Farm oilfield of southern England offers a splendid example.

Cross-section through the Wytch Farm oilfield, southern England. The oil is in two reservoirs, trapped against faults to the south; these predated the deposition of the Upper Cretaceous.; Tr, Triassic; L, Lower Jurassic; BS+MJ+O, Middle Jurassic; Kim+P, Upper Jurassic; W, Lower Cretaceous; UK, Upper Cretaceous; T, Tertiary. (2-28)

We do not propose to discuss fault traps in detail, although there are many problems in trying to locate them in the subsurface, and in understanding them. Whether or not there is a trap, and how big it is, will depend on the dip of the reservoir as compared with that of the fault, whether the fault is normal or reverse; and it will depend on the amount of displacement on the fault, whether or not the reservoir is completely or only partially offset. It also depends on whether the fault itself is sealing or non-sealing.

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, thus causing sand against sand to permit migration and sand against shale to be sealing.

The sealing capacity of faults is a major difficulty confronting us. We know that sometimes, as at Wytch Farm, a fault can provide a seal, but we also know that sometimes faults are pathways for migrating petroleum and non-sealing at all. Occasionally indeed, it seems that one and the same fault may act, or have acted in the past, in both ways. All very puzzling! Although attempts have been made to investigate the problem in Nigeria and elsewhere, and naturally we have some ideas on the subject, we still do not fully understand what the difference is due to. It adds further uncertainties to our predictions of the subsurface occurrence of oil and gas.

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Six trapping and two non-trapping configurations against a fault, depending on whether the fault is normal or reverse, on the direction of dip of the beds relative to the fault plane, and on the amount of displacement of the reservoir. It is presumed that petroleum cannot escape up the fault plane.(2-29)

STRATIGRAPHIC TRAPS Petroleum may be trapped where the reservoir itself is cut off up-dip, thus preventing further migration; no structural control is needed. The variety in size and shape of such traps is enormous, to a large extent reflecting the restricted environments in which the reservoir rocks were deposited. 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, and leave the reader to speculate on other possibilities.

First, however, let us note that a number of traps, some of them very important, are formed by unconformities; they differ somewhat in principle from the others, but are generally classified as stratigraphic traps. A dipping reservoir, cut across by erosion and later covered above the unconformity by impermeable sediments, provides the classic case: the East Texas field, for example, is the biggest in the USA outside Alaska.

Unconformity traps can also be found above the break. Consider the sea gradually encroaching over the land as sea level rises; the beach sands will spread progressively over the land surface, becoming younger as time goes on, until perhaps the supply of sand runs out. We would be left with a sandstone reservoir dying out above the unconformity, to provide a trap when later covered with, say, claystone.

More esoterically, but nevertheless known, a hill on the old land surface may be formed of permeable rock; if drowned by shales, the porosity could be preserved beneath the unconformity. In this manner, strongly weathered basement rock (granites, gneisses) under an unconformity serve as reservoirs in China and North Africa.

Non-unconformity traps are even more diverse. We mention just three examples. A coral reef overwhelmed by muds, may serve as an isolated stratigraphic trap. A sand deposited in a river channel will be confined by the banks and, if terminated updip as not infrequently happens, we have an isolated trapping situation. A flood of sand washed off the shallow continental shelf into the deeper ocean, possibly through a submarine canyon, will spread out as a fan over the ocean floor; its edges will provide an example of a reservoir dying out laterally. A lot of oil has been found in recent years in this sort of trap in the North Sea. In fact, fan sands provide one of the prime present-day exploration

Petroleum Traps - 42

targets, although such prospects are not easy to locate and may require a lot of sophisticated seismic.

As the more easily found structural traps are running out in much of the world, there always seems to be something new as a challenge.

An investigation into the sealing qualities of faults affecting roll-over anticlines in the Niger Delta, where the reservoirs overlie overpressured shales. Where a reservoir is full to spillpoint against a fault, and where an oil-water contact is continuous across a fault, it is presumed that the fault is non-sealing; elsewhere it appears to form a trap. The difference is believed to be due to clay being smeared into the fault plane, where there is enough of it in the section, as the fault moved.(230)

COMBINATION TRAPS A number of fields, some of them large, occur in traps formed by a combination of structural and stratigraphic circumstances; neither completely controls the trap. Again the range of possibilities is almost infinite. A couple of examples may give the idea.

The Prudhoe Bay field in northern Alaska, the biggest field in the USA, has most of its oil and gas trapped in a Carboniferous to Jurassic sequence which includes more than one reservoir; these beds were folded into a faulted east-west anticline, tilted westwards, and truncated by erosion. The oil is held in the reservoirs by younger shales overlying the erosion surface (Fig.).

A block representation of the trap at the Prudhoe Bay field in northern Alaska. The reservoir beds were folded into an anticline, which was tilted west and eroded before deposition of the overlying beds now dipping east. This combination trap is partly structural (the anticline) and partly stratigraphic (beneath the unconformity).(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, which were eroded and unconformably overlain by Cretaceous shales. Both the faulting and the unconformity control the traps.

We may note here one most important consideration. The oil in these fields can only have migrated there after the traps were sealed by the higher sequences, or the oil would have been lost. This vital factor, that the trap must be shown to have been there before the oil migrated, possibly even before it

Petroleum Traps - 43

was generated, is yet another aspect of the petroleum geology that we have to assess in proposing exploration drilling. The timing of trap formation versus oil migration has not always worked out favorably.

HYDRODYNAMIC TRAPS Imagine surface water, perhaps from rain, entering a reservoir formation, or aquifer, up in the hills and percolating downwards towards a spring. Oil has found its way into the reservoir and is battling to migrate upwards to the surface against the flow of water. Depending on the balance of forces acting on the oil, it may find itself caught against an unevenness of the reservoir surface where there is no conventional trap at all. This is what has been described as a hydrodynamic trap. It is totally dependent on the flow of water and is effective, of course, only for as long as the water keeps coming: dry up the supply of water, and the oil will be free to move again. This may be one of the reasons why oil accumulations trapped hydrodynamically are rare; a regime of water flow cannot normally be expected to remain constant for long, geologically speaking.

The oil-water contact in such a hydrodynamic trap is normally tilted in the direction of water flow.

Such tilted contacts, in say ordinary anticlinal traps, are not all that rare; they are known in a number of parts of the world. In this sort of situation, we would have to be careful where we locate and drill our oil production wells, as we do not want to waste the money drilling wells that would miss the oil altogether. Furthermore, cases are known where flowing water has apparently been able totally to flush oil out of an anticlinal trap. We would recognize this from residual traces of oil in a water-bearing reservoir, indicating the former presence of an oil accumulation now lost. It is therefore always important to get a handle on the hydrodynamic regime in a reservoir for both exploration and oilfield development purposes.

A hydrodynamic trap. Oil, attempting to escape to surface up a reservoir, is held against an unevenness of its upper surface by water flowing in the opposite direction. There is no structural or stratigraphic closure. Note that the oil-water contact is tilted down in the direction of water flow.(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, essentially anticlinal, traps in both number and size. The number of structural field of this size may partly reflect the fact that structural traps are easier to find than the others, but the oil reserves they contain show clearly that generally they are also bigger. The trouble, from our present-day point of view, is that in most parts of the world the larger anticlines have now been drilled. What our efforts are increasingly directed towards, therefore, are the more obscure and generally smaller prospects.

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EXERCISES EXERCISE 1: The following well logs have been hung on a structural datum. Interpret the geological relationships shown in each by drawing a structural cross-section through the logs. The logs show SP (Self Potential or Spontaneous Potential) on the left and R (Resistivity) on the right.Make the interpretations from easy (A) to more difficult, multi-interpretable (D).

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EXERCISE PetroleumTraps 2 The Wyckoff Gas Field, located in Steuben County, N.Y., produces from Onondaga Limestone and/or Oriskany Sandstone. The Onondaga forms a thick biohermal reef over part of the field. Only the porous core facies is productive in the reef section (see map on next page). A deep-seated downto-the-southwest fault extends upward along the southwest flank of the reef.

Oriskany production is from a small anticline on the upthrown side of the fault.

Elevations and marked logs are provided for 6 wells in the Wyckoff Field. Use this information to construct a northeastsouthwest structural cross section from the Richards well to the Dibble well, showing the interval from top of Onondaga to bottom of Oriskany.

Wyckoff Reef Gas Field WellElevation CORNELL DIBBLE GUILD CHASE BANKS RICHARDS

2257' 2098' 2037' 2206' 2182' 2066'

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8 - Source-Rock Evaluation DEFINITION OF SOURCE ROCK Much of modern petroleum geochemistry depends upon accurate assessment of the hydrocarbonsource capabilities of sedimentary rocks. Although the term source rock is frequently used generically to describe fine-grained sedimentary rocks, that usage is a bit too broad and loose. For better communication. the following distinctions can be made: Effective source rock: any sedimentary rock that has already generated and expelled hydrocarbons.

Possible source rock: any sedimentary rock whose source potential has not yet been evaluated, but which may have generated and expelled hydrocarbons.

Potential source rock: any immature sedimentary rock known to be capable of generating and expelling hydrocarbons if its level of thermal maturity were higher.

It follows from these definitions that a particular stratum could be an effective source rock in one place; a potential source rock in a less-mature area; a possible source rock in a nearby unstudied region; 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. For example, the Phosphoria Formation of Wyoming and Idaho belongs to each of these classifications in different areas.

The term "effective source rock" obviously encompasses a wide range of generative histories from earliest maturity to overmaturity. When we analyze a rock sample in the laboratory, we actually measure its remaining (or untapped) source capacity at the present day. This quantity, which we can call G, is most meaningful if we can compare it to the rock's original source capacity, Go. The difference between Go and G represents the hydrocarbons already generated in the effective source rock. However, we cannot measure G directly for a sample that has already begun to generate hydrocarbons; instead it must be estimated by measuring G for a similar sample that is still immature. Go can only be measured directly for immature source rocks, 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. This simple, quick, and inexpensive analysis serves as the first and most important screening technique in source-rock analysis. Analysis normally requires about one gram of rock, but if the rocks contain abundant organic matter, much smaller amounts can be analyzed.

The quantity actually measured in the laboratory is always G, the remaining source capacity and not the original capacity (Go).

MATURITY OF ORGANIC MATERIAL Knowing a rock's remaining source capacity G solves only one part of the puzzle; it is also necessary to know what level of thermal maturity is represented by that particular G value. For example, if G is very low, is it because the rock never had a high initial source capacity, or is it because the rock is "burned out" (i.e., overmature, in which case virtually all the initial

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hydrocarbon-source capacity has already been used up)? The exploration implications of these two scenarios are, of course, very different.

A substantial number of techniques for measuring or estimating kerogen maturity have been developed over the years. All the methods have strengths and weaknesses, and none can be applied in all cases.

The feeling of most workers today is that there is no single maturity indicator that tells the whole story unerringly all the rime. All the techniques discussed are useful and probably reasonably accurate if the analytical work is carefully done. The key to using maturity parameters effectively lies in evaluating the measured data carefully (and sometimes with skepticism) and, whenever possible, in obtaining more than one maturity parameter.

The most commonly used maturity parameters today are spore color (Thermal Alteration Index, or TAI), vitrinite reflectance, and pyrolysis temperature. Less commonly used are fluorescence and conodont color (CAI). A few of these parameters will briefly be discussed.

Vitrinite reflectance (Ro). Vitrinite-reflectance techniques were developed for measuring the rank of coals, in which the vitrinite maceral is usually very common. The method is based on the fact that with increasing thermal stress, the reflectance value of vitrinite increases.

Vitrinite-reflectance measurements begin by isolating the kerogen with HCl and HF, and then embedding the kerogen particles in an epoxy plug. After the plug is polished, the microscopist shines light on an individual vitrinite particle. The fraction of the incident beam that is reflected coherently is measured and recorded and stored automatically on a computer. If enough vitrinite particles can be found, between 50 and 100 measurements will be taken. At the end of the analysis a histogram of the collected data is printed, along with a statistical analysis of the data. Results are reported as Ro values, where the o indicates that the measurements were made with the plug immersed in oil. Reflectance values are normally plotted versus depth in a well. If a log scale is used for the reflectance, the plot is a straight line.

There are many problems with vitrinite reflectance as applied to kerogens. In many rocks vitrinite is rare or absent. Because what is present is often reworked, its maturity is not related to that of the rock in which it is found. Reworked vitrinite is, in fact, far more common in shales than in coals, leading to frequent difficulties in establishing which vitrinite population is indigenous. The ideal histogram of reflectance values is therefore rather rare; 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. Such histograms are quite often difficult or impossible to interpret, unless surrounding samples help us determine the indigenous vitrinite population.

Other macerals or solidified bitumens can often be misidentified as vitrinite. Because each maceral type increases in reflectance in a slightly different way as thermal stress increases, misidentification of macerals can cause problems, even for experienced workers.

Despite its weaknesses, vitrinite reflectance is the most popular technique today for estimating kerogen maturity. In many areas it is easy to use and valuable. In other rocks, however, paucity of first-cycle vitrinite renders vitrinite-reflectance measurements essentially worthless. In all cases it is worthwhile to supplement vitrinite with other measures of maturity; in some cases it is essential.

Thermal Alteration Index (TAI). TAI measurements are made on the same slides prepared for microscopic kerogen-type analysis. The darkening of kerogen particles with increasing thermal maturity can be used as an indicator of maturity. In order to minimize differences in color caused by changes in the type or thickness of the kerogen particles, TAI measurements are carried out on bisaccate pollen grains whenever possible. If no pollen can be found, TAI values are estimated, with lower confidence, from amorphous kerogen.

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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, thus defusing to a large degree the criticism that TAI is too subjective to be valid.

Although TAI determinations are subjective, use of careful standards and the same type of palynomorph in each analysis greatly aid reproducibility. TAI measurements are therefore often quite accurate and correlate very well with results from other techniques. The chief problems arise with inexperienced workers, lack of proper standardization, or most commonly, the absence of spores and pollen in the samples. When palynomorphs are absent, TAI values must be estimated from amorphous debris, which can vary greatly in its chemical and physical properties. TAI values estimated from amorphous material are always suspect and should be corroborated by other analyses.

Conodont Alteration Index (CAI). Conodonts are isolated, most commonly from fossiliferous carbonates, by removing the mineral matrix with acetic or formic acid. Colors of the specimens thus obtained are determined under a binocular microscope and compared with standards. The technique is simple and quick and can be done even by inexperienced workers.

Although conodonts are composed of carbonate apatite, 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, they offer a means of measuring maturity in rocks that do not contain pollen grains or vitrinite. Furthermore, conodonts are plentiful in carbonate rocks, where pollen and vitrinite are often absent. Thirdly, the CAI scale is most sensitive at levels of maturity much higher than can be measured by TAI, and thus helps expand the range over which maturities can be measured. Finally, CAI is inexpensive and easy to measure and, with the help of color charts can be carried out by inexperienced personnel.

One disadvantage of CAI measurements is that CAI values can be dramatically increased in the presence of hot brines, leading to an inaccurate assessment of kerogen maturity. Other disadvantages overlap with some of the advantages. Conodonts do not occur in rocks younger than the Triassic, and thus are of no value in many areas. Conodonts are not very sensitive indicators of maturity within the oil generation window, where most of the interest is. Finally, because the organic metamorphism displayed by conodonts is not related to hydrocarbon generation or destruction, CAI is only an indirect indicator of hydrocarbon maturity.

Carbon Preference Index (CPI). The first maturity indicator applied to sediments was the Carbon Preference Index. Early investigations showed that immature rocks often had high CPI

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values (> 1.5), whereas those of oils were almost always below 1.2. This discovery led to the use of CPI as an indicator of maturity. 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. In particular, rocks deposited in pelagic environments, in which the input of terrestrial lipids was very limited, have low CPI values even when immature.

Furthermore, in the last decade kerogen analyses have replaced bitumen analyses as the routine procedure in source-rock evaluation. As a result, fewer CPI determinations are made now.

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. Problems with living organic matter are easily avoided by physically removing tiny plant roots and other recognizable debris. Mold or other surface growth may also be present. Hydrocarbon contamination is rare except in the immediate vicinity of production or where vehicles are used, and therefore should be easy to avoid.

Well Samples - The main causes of contamination among samples obtained from wells are caving and adulteration by drilling-fluid additives. Caving is not a problem for conventional or sidewall cores, of course, but it can be devastating in cuttings samples. Careful picking of lithologies and comparison with up-hole samples can often recognize caved materials. In many cases, however, vitrinite reflectance measurements offer the best means of recognizing caving. Caving is a particular problem for coals, because of their friability; it can lead to an overly optimistic assessment of the organic richness of the section.

Drilling-fluid additives have been a severe headache for petroleum geochemists for a long time.

Contaminants of particular notoriety are diesel fuel, walnut hulls and other solid debris, and lignite from lignosulfonates. Fortunately, palynological analysis can usually detect the presence of lignosulfonates because of the unique pollen assemblages present in the lignite. In such cases TOC values will be raised and reflectance histograms will show a large population near 0.5%. Walnut hulls and other organic debris are also easy to detect microscopically, and can be removed prior to beginning the analytical sequence.

In contrast to solid additives, which affect only the kerogen portion of the sample, diesel fuel affects both kerogen and bitumen. It is capable of impregnating sidewall and conventional cores as well as cuttings. TOC values will be raised and vitrinite-reflectance values lowered by the presence of adsorbed diesel.

ESTIMATION OF ORIGINAL SOURCE CAPACITY Of the three major methods of determining kerogen type, only microscopic analysis is relatively unaffected by maturity. As long as kerogen particles are not completely black, they can usually be identified with reasonable confidence. The exception to this rule is with amorphous material, where the fluorescence that enables us to distinguish between oil-prone and non-oil-prone disappears toward the end of the oil-generation window.

Pyrolysis yields are, of course, strongly affected by maturity. 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. This method works fairly well if the kerogen is still within the oil-generation window. It breaks down at high maturity levels, however, because all kerogens have low pyrolysis yields. Without additional information, therefore, it is impossible to determine which maturation path brought it to that point.

Like pyrolysis, atomic H/C ratios measure the present day status of the kerogen rather than its original chemical composition. Atomic H/C ratios must therefore be corrected for the effects of

Source Rock Evaluation - 53

maturation by using a van Krevelen diagram. These immature H/C ratios can then be used to calculate Go.

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. Because the density of organic matter is about one-half that of clays and carbonates, the actual volume percent occupied by the organic material is about twice the TOC percentage.

Those rocks containing less than 0.5% TOC are considered to have negligible hydrocarbon-source potential. The amount of hydrocarbons generated in such rocks is so small that expulsion simply cannot occur. Furthermore, the kerogen in such lean rocks is almost always highly oxidized and thus of low source potential.

Rocks containing between 0.5% and 1.0% TOC are marginal. They will not function as highly effective source rocks, but they may expel small quantities of hydrocarbons and thus should not be discounted completely. Kerogens in rocks containing less than 1% TOC are generally oxidized, and thus of limited source potential.

Rocks containing more than 1% TOC often have substantial source potential. In some rocks TOC values between 1% and 2% are associated with depositional environments intermediate between oxidizing and reducing, where preservation of lipid-rich organic matter with source potential for oil can occur. TOC values above 2% often indicate highly reducing environments with excellent source potential.

Interpretation of TOC values therefore does not simply focus on the quantity of organic matter present. A rock containing 3% TOC is likely to have much more than six times as much source capacity as a rock containing 0.5% TOC, because the type of kerogen preserved in rich rocks is often more oil-prone than in lean rocks. We therefore use TOC values as screens to indicate which rocks are of no interest to us (TOC < 0.5%), which ones might be of slight interest (TOC between 0.5% and 1.0%), and which are definitely worthy of further consideration (TOC > 1.0%).

Many rocks with high TOC values, however, have little oil-source potential, because the kerogens they contain are woody or highly oxidized. Thus high TOC values are a necessary but not sufficient criterion for good source rocks. We must still determine whether the kerogen present is in fact of good hydrocarbon-source quality.

TYPE OF ORGANIC MATTER Microscopic kerogen-type analysis describes the proportions of the various macerals present in a sample. In interpreting these observations we normally divide these macerals into oil-generative, gas-generative, and inert. The oil-generative macerals are those of Type I and Type II kerogens: alginite, exinite, resinite, cutinite, fluorescing amorphous kerogen, etc. Gas-generative kerogen is mainly vitrinite.

Inertinite is considered by most workers to have no hydrocarbon-source capacity. Smyth (1983), however, has dissented from this pessimistic view, claiming, on the basis of deductive reasoning, that at least some Australian inertinites can generate significant amounts of oil. Nevertheless, the direct evidence for such a statement is rather meager.

Pyrolysis results are normally reported in two ways. Raw data (S1, S2, and S3) are expressed in milligrams of hydrocarbon or carbon dioxide per gram of rock sample. As such these quantities are a measure of the total capacity of a rock to release or generate hydrocarbons or carbon dioxide. These raw data are then normalized for the organic-carbon content of the sample, yielding

Source Rock Evaluation - 54

values in milligrams per gram of TOC. The normalized S2 and S3 values are called the hydrogen index and the oxygen index, respectively. Because variations in TOC have been removed in the normalizing calculation, the hydrogen index serves as an indicator of kerogen type.

Measured hydrogen indices must be corrected for maturity effects by using a modified van Krevelen diagram as outlined above. Interpretation of hydrogen indices for immature kerogens is straightforward. 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. Hydrogen indices above 150 reflect increasing amounts of lipid-rich material, either from terrestrial macerals (cutinite, resinite, exinite) or from marine algal material. Those between 150 and 300 contain more Type III kerogen than Type II and therefore have marginal to fair potential for liquids. Kerogens with hydrogen indices above about 300 contain substantial amounts of Type II macerals, and thus are considered to have good source potential for liquid hydrocarbons.

Kerogens with hydrogen indices above 600 usually consist of nearly pure Type I or Type II kerogens. They have excellent potential to generate liquid hydrocarbons.

MATURITY Kerogen Parameters. Determination of the oil-generation window in a particular section is the objective of most maturity analyses performed on possible source rocks. A second, less common application is to decide whether oil will be stable in a given reservoir. The limits of the oil generation window vary considerably depending upon the type of organic matter being transformed. Nevertheless, for most kerogens the onset of oil-generation is taken to be near 0.6% Ro. Peak generation is reached near 0.9% Ro, and the end of liquid-hydrocarbon generation is thought to be at about 1.35% Ro. The ultimate limit of oil stability is not known for certain, but in most cases is probably not much above 1.5% Ro. Because vitrinite reflectance is the most popular method of determining maturity, most other maturation parameters are related to Ro values. The correlations among maturity parameters have been fairly well established, but there are still some minor variations from one laboratory to another.

It is particularly difficult to generalize about TAI values because the numerical values of TAI scales have not been standardized among laboratories. Thus, if you are using TAI determinations determined by an analytical laboratory, make sure that you have a copy of their equivalency between TAI and Ro. Although Tmax values are determined objectively, because they vary with kerogen type as well as maturity, a unified scale for comparing them with Ro values has not been adopted. Some laboratories put the onset of maturity at 435째 C; others use 440째.

Conodont Alteration Index (CAI) values ranging from 1 to 5 were tied loosely to vitrinite reflectance and fixed carbon content of coals. CAI can actually measure high-grade metamorphism, with CAI of 8 reached in a marble.

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. However, this generalization has two fallacies: most of the coalfields originally studied were of Paleozoic age, and the coals were of bituminous to anthracite rank.

Age of coals is important, because during the Paleozoic the biota was quite different than during the Cenozoic. Because some Cenozoic land plants are richer in resins and waxes than Paleozoic plants, some Cenozoic coals should have better potential for generating liquid hydrocarbons.

Source Rock Evaluation - 55

SUMMARY Any source-rock evaluation should attempt to answer three questions: What are the quantity, type, and maturity of the organic matter present in the rocks? Satisfactory methods are available in most cases to answer all these questions. In some areas one technique may fail completely or may be only partially successful. Whenever possible, therefore, we should not rely on a single analytical technique; rather, we should attempt to corroborate the measured data by other analyses.

Interpretation of source-rock data on a basic level is quite simple. With increasing experience one can also learn to derive important information on thermal histories, unconformities and erosional events, and organic facies.

We should always attempt to extrapolate our measured data over as large an area as possible. To do this intelligently we must have the ability to develop regional models of organic facies and thermal maturity.

Vitrinite Reflectance (%Ro) 0.40 0.50 0.60 0.80 1.00 1.20 1.35 1.50 2.00 3.00 4.00

Thermal Alteration Index (TAI)

Pyrolysis Tmax (째C)

2.0 2.3 2.6 2.8 3.0 3.2 3.4 3.5 3.8 4.0 4.0

420 430 440 450 460 465 470 480 500 500 + 500 +

Conodont Alteration Index (CAI) 1 1 1 1.5 2 2 2 3 4 4 5

Correlation of various kerogen-maturity parameters with vitrinite-reflectance (Ro) values

Source Rock Evaluation - 56

EXERCISES Worked out example: Perform a source-rock analysis on the Mauve Well.

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

Core Cuttings

%Corg

Atomic H/C

TAI

0.6 0.8 0.5 0.3 1.3 0.7 1.6 2.5 0.5 1.2 1.0 0.7 1.5 1.7 2.1 2.2

1.07 1.22 1.05 0.65 0.77 0.81 1.33 1.27 1.15 0.98 0.86 0.75 0.72 0.66 0.41 0.38

2.0 2-2.5 2-2.5 2-2.5 2.2 2.6 2.5 2.5 2.6 2.7 2.9 3.0 3.1 3.2 3.7 3.8

% Alginite + Exinite 75 80 80 75 80 90 85 75 70 50 45 60 45 40 ? ?

Data are available on quantity (%Corg), quality (H /C and %Alginite + Exinite), and maturity (TAI), so "Total Oil" can be plotted against "Oil Already Generated." Two independent quality measurements have been made, and both should be utilized and examined for possible discrepancies. To use the H /C data, however, one must first convert the measured, present-day H/C ratios to the ones that the kerogens had when they were thermally immature. This can be done easily by plotting H/C versus TAI, as shown in Figure B (derived from Figure A), and then tracing the H/C ratio back to its immature value. The calculated immature H/C ratios are listed in the table on next page.

A) Calculation of the immature kerogen H/C ratio(at A) from the present-day H/C ratio and vitrinite reflectance data(at P) .

B) H/C versus TAI for Mauve Well samples.

Both the immature H / C ratios and the maceral analysis data need to be scaled to calculate "Total Oil." To do this, refer to the graph on next page, presenting the kerogen quality factor as a

Source Rock Evaluation - 57

function of H/C ratio of the immature kerogen in order to determine the quality factor from H/C. In likewise manner (not illustrated here) the quality factor can be determined from maceral analysis data. The scaled quality factors are given for each parameter in the table on next page.

Kerogen quality factor as a function of H/C ratio of the immature kerogen.

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

Immature H/C

1.07 1.22 1.05 0.65 0.77 0.81 1.33 1.27 1.15 0.98 0.86 0.75 0.72 0.66 0.41 0.38

1.07 1.22 1.05 0.65 0.77 0.81 1.35 1.30 1.20 1.05 1.05 0.90 0.90 0.90 ? ?

Quality Factor Quality Factor (from H/ C) (from 1.05 1.50 1.00 0.17 0.35 0.43 1.85 1.70 1.35 0.90 0.90 0.60 0.60 0.60 ? ?

* * * * *

* *

1.5 1.6 1.6 1.5 1.6 1.8 1.7 1.5 1.4 1.0 0.9 1.2 0.9 0.8 ? ?

* Indicates discrepancy between quality factors calculated from H /C and from maceral analysis.

It is apparent that there are serious discrepanties between the H/C and maceral analysis results for several of the samples. The samples at 1000, 1500, 1750, 2000, 2300, 4000, and 4500 meters all show differences in the quality factors calculated from the two types of data. In each case, the H/C ratio gives the lower quality factor, so some systematic error is likely. Without more knowledge, however, it is impossible to pinpoint the error. The prudent interpreter might now ask that some of the H/C ratios be rerun, to check for analytical error, and would certainly request that the slides made for maceral analysis be reviewed. If these attempts produced no resolution of the problem, the interpreter might then decide to try a third technique, such as pyrolysis. The most important point being made here is that these discrepanties must be taken seriously by the interpreter, and not

Source Rock Evaluation - 58

be overlooked or swept under the rug. It may be necessary occasionally to offer two alternative interpretations without choosing between them. Let us take this last approach to this problem.

The rest of the section shows a good correspondente between the two parameters, except for the two deepest samples. These two kerogens are highly mature and quite black. In fact, no maceral analysis was possible here, and the H/C ratios are not helpful because the maceral types cannot be ascertained from such low H/C values. One can say little, therefore, about the oil-source history of the section below 4600 meters.

"Total Oil" and "Oil Already Generated" profiles tor the Mauve Well.

"Total Oil" and "Oil Already Generated" profiles are plotted in above figure. Most of the discrepanties among the different quality factors turn out to be unimportant, because sourcerock potential is not good for most of the section. The only sample where the discrepancy is significant is that from 2000 meters. "Total Oil" values are generally unexciting, although the section between 2000 and 3500 meters shows fairly good potential. More samples between 3000 and 3500 meters should be obtained to define better the zone of high "Total Oil" values.

"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. The relative organic richness of the blackened samples below 4600 meters makes them interesting for further investigation. Finally, 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. Future exploratory activity could include an attempt to find such a section.

Source Rock Evaluation - 59

EXERCISE Source Rock 1 Combine the data from the Blue Well to give a coherent picture of thermal maturity in the section drilled. Explain how you resolved any apparent discrepancies.

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 2.0 2.0 2.0 2.0-2.5 2.0 2.3 2.3 2.0 2.0-2.5 2.2 2.5 2.5 2.0-2.5 2.6 2.5 2.5 2.6

0.42 0.49 0.46 0.55 0.60 0.51 0.59 0.63 0.60

0.05 0.07 0.02 0.10 0.08 0.09 0.06 0.17 0.25 0.44 0.66 0.61 0.21 0.03 0.07 0.09 0.11 0.12

*TAI and Ro are interconverted according to the correlation table at the end of chapter 7.

EXERCISE Source Rock 2 Perform a source-rock evaluation of the section penetrated in the Turquoise Well.

Source-rock data tor the Turquoise Well Depth (ft)

Type of Sample

3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10,000

Cuttings Cuttings

TOC

Bit/TOC

Atomic H/C

1.0 0.8 0.7 0.9 1.1 2.3 2.6 4.1 0.5 0.3 1.8 1.7 0.2 0.4 0.3

0.06 0.06 0.05 0.08 0.91 0.66 0.22 0.51 0.08 0.08 0.27 0.18 0.01 0.03 0.02

0.90 0.85 0.86 1.02 0.91 1.25 1.21 1.17 0.65 0.71 0.99 1.03 0.60 0.51 0.48

TOC = Total Organic Carbon Bit/TOC = Bitumen/Total organic carbon ? indicates a poor histogram

Ro 0.49 0.52 0.59 0.65 0.67 0.88 0.91 1.00 1.07 1.27 1.21 1.26?

1.41?

1.33?

1.51

TAI

% Alginite + Exinite

2-2.5 2.5 2.5 2.5-3 2.5-3 2.5-3 2.5-3 2.5-3 3.0 3-3.5 2.5-3 2.5-3.5 3.5 3-3,5 3.5

TAI = Thermal Alteration Index Ro = Vitrinite reflectance

40 30 35 40 50 80 75 75 25 40 70 80 20 15 10

Predicting Thermal Maturity - 60

9 - 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. In most cases, however, measured maturity data are of limited value in exploration. Part of this problem is a consequence of the limitations we face in attempting to obtain reliable maturity measurements. In some areas there are no well samples available; indeed, in frontier basins there may not be a single well within tens or hundreds of kilometers.

Even in maturely explored basins the samples available for analysis often do not give a representative picture of maturity in the basin. Furthermore, maturity measurements can only tell us about present-day maturity levels. If our measurements indicate that a rock has already passed through the oil-generation window, we still have no clue as to when oil generation occurred, nor do we know at what depth or temperature it occurred. These considerations are important when we want to compare timing of generation, expulsion, and migration with timing of structure development or trap formation.

In order to circumvent these difficulties, methods have been developed for calculating maturity levels where measurements are not available.

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.

This assumption is a logical and defensible one, for it is in keeping with the predictions of chemical-kinetic theory.

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. Nevertheless, 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. In 1971, however, 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.

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. It has even been suggested that maturity models are more accurate than measured data for determining the extent of petroleum generation.

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.

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. We need data that will enable us to construct a time stratigraphy for the location of interest and to specify its temperature history. Time-stratigraphic data are usually available as formation tops and ages obtained by routine biostratigraphic analysis of well cuttings. If no well data are available, a time stratigraphy can sometimes be constructed using seismic data, especially if the seismic reflectors can be tied to well data. If no subsurface data are available, estimates can be made, perhaps from thicknesses of exposed sections nearby.

Predicting Thermal Maturity - 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. An example is shown in the following figure, which was constructed from the time stratigraphy for the Tiger well. In the Tiger well, sediment has accumulated continuously but at varying rates since deposition of the oldest rock 100 million years ago (Ma).

Today the rock is at a depth of 3700 m. The burial-history curve was constructed in the following way: two points, representing the initial deposition of the sediment (point A) and its position today (point B), are marked on the age-depth plot.

The next step is to locate the first control point from the time-stratigraphic data on the input table.

Neglecting compaction effects, by 80 Ma the sediment had been buried to a depth of 900 m (point C). Using the other control points from the input table, we can construct the complete figure.

Connecting the six dots completes the burial-history curve.(9-2)

All of the shallower and younger horizons will have burial-history curves whose segments are parallel to those of the oldest horizon. This geometry is a direct consequence of ignoring compaction effects.

Burial-history curves are based on the best information available to the geologist. In cases where biostratigraphic data are available and deposition has been reasonably continuous, it is easy to construct burial-history curves with a high level of confidence. In cases where biostratigraphic data are lacking or where the sediments have had complex tectonic histories, a burial-history curve may represent only a rather uncertain guess. Nevertheless, if constructed as carefully as the data permit, burial-history curves represent our best understanding of the geological history of an area.

TEMPERATURE HISTORY The next step is to provide a temperature history to accompany our burial-history curve. The subsurface temperature must be specified for every depth throughout the relevant geologic past.

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.

Suppose, for example, that the Tiger well was logged, and that a corrected bottom-hole temperature of 133째 C was obtained at 3800 m. Suppose further that local weather records indicate a yearly average surface temperature of 19째 C. Using these present-day data and extrapolating them into the past, we can construct the temperature grid with equally spaced isotherms parallel to the earth's surface.

Predicting Thermal Maturity - 62

Where measured bottom-hole temperatures are not available, maps of regional geothermal gradients can be useful in estimating the gradient at a particular location. In many poorly explored areas, temperature profiles will be based largely on guesswork.

There are numerous other variations that can be employed in creating temperature grids. For example (9-7), we can change surface temperatures through time without altering the geothermal gradient. Causes for such events could include global warming and cooling or local climatic variations resulting from continental drift or elevation changes.

In other cases the surface temperature remains constant, but the geothermal gradient varies in response to heating or cooling events. 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. More complicated temperature histories account for changes in thermal conductivities caused by variations in lithology.

There is no theoretical limit to the complexity that can be introduced into our temperature histories.

Given adequate data or an appropriate model on which to base complex temperature reconstructions, we are limited only by our own creativity. In most cases, however, the data necessary for highly sophisticated temperature reconstructions are simply not available.

SPECIAL CONSIDERATIONS ABOUT BURIAL-HISTORY CURVES The most common complicating factor in constructing burial-history curves is erosional removal.

Erosion is indicated in a burial-history curve by an upward movement of the curve. If deposition resumes later, the burial-history curve again begins to trend downward.

Whenever erosional removal occurs, the resultant thinning of the section must be represented in the entire family of burial-history curves. The individual segments of each of the burial-history curves in a family will remain parallel.

Faulting can be dealt with by considering the hanging wall and footwall as separate units having distinct burial histories. 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. If, however, some part of the section is repeated as a result of thrusting, two separate diagrams should be used for the sake of clarity.

The effects of thrusting on thermal maturity are not well understood. If thrusting is rapid compared to the rate of thermal equilibration between thrust sheets, the movement of hot rocks from the bottom of the overthrusted slab over cool rocks at the top of the underthrusted slab will affect

Predicting Thermal Maturity - 63

organic maturation by causing important perturbations in subsurface temperatures. Studies in the Overthrust Belt of Wyoming indicate that a slow-equilibration model is superior to a simple model invoking rapid thermal equilibration. However, more work is required before we will understand fully how thrusting influences hydrocarbon generation and destruction.

Loss of 1000 m of section by erosion during an uplift event lasting from 70 Ma to 60 Ma. Individual burial-history curves remain parallel, but the distance between the two lines which bracket the erosion, decreases by 1000 m.(9-12)

CALCULATION OF MATURITY Once the burial-history curves and temperature grids have been constructed, we must paste them together. Intersections of the burial-history curve with each isotherm are marked with dots. These dots define the time and temperature intervals that we shall use in our calculations. Temperature intervals are defined by successive isotherms spaced 10° C apart. A Time interval is the length of time that the rock has spent in a particular temperature interval. Total maturity is calculated by summing the incremental maturity added in each succeeding temperature interval.

Now we can carry out the maturity calculations. 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 16,400 cal/mol will approximately double with every 10° C increase in reaction temperature. 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.

In order to carry out maturity calculations conveniently, we need to define both a time factor and a temperature factor for each temperature interval. Lopatin defined each time factor simply as the length of time, expressed in millions of years, spent by the rock in each temperature interval.

The temperature factor, in contrast, increases exponentially with increasing temperature. Lopatin chose the 100°-110° C interval as his base and assigned to it an index value n = 0. Index values increase or decrease regularly at higher or lower temperatures intervals, respectively. Because the rate of maturation was assumed to increase by a factor of two for every 10° C rise in temperature, for any temperature interval the temperature factor (?) was given by: ? = 2n The temperature-factor thus reflects the exponential dependence of maturity on 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). This intervalTTI value represents the maturity acquired by the rock in that temperature interval during the time

Predicting Thermal Maturity - 64

given. To obtain total maturity, we simply sum all the interval-TTI values for the rock. Maturity always increases; it can never go backward because interval-TTI values are never negative.

Furthermore, even if a rock cools down, maturity continues to increase (albeit at a slower rate) because y is always greater than zero.

A good analogy can be drawn between oil generation and baking. If we put a cake in a cold oven and turn the oven on, the cake will bake slowly at first but will bake faster and faster as the temperature rises. If we turn off the oven but leave the cake inside, baking will continue, although at increasingly slower rates, as the oven cools down. On the other hand, if we forget about the cake when the oven is hot and let it burn, we cannot "unburn" it, no matter how much or how rapidly we cool it down.

The first step in calculating TTI is illustrated in the following figure, where the time factors and yfactors for each temperature interval are shown on the burial-history curve. In the adjoining table interval-TTI values and total-TTI values up to the present day are calculated.(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.

FACTORS AFFECTING THERMAL MATURITY Because maturity is affected by both baking time and baking temperature, the specific burial history of a rock can strongly affect its maturity.

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). In A the rock was buried at a constant rate for its entire 80-my history.

In B burial was very slow during the first 70 Ma of the rock's existence, but quite rapid in the last 10 my.

Figure C shows rapid burial during the first 20 Ma, followed by a nonerosional depositional hiatus for the last 50 Ma. In D 40 Ma of rapid burial to a depth of 4000 m was followed by a hiatus lasting 30 Ma and, finally, by 10 Ma of uplift and erosion.

TTI values differ appreciably among these four scenarios.

Predicting Thermal Maturity - 65

A) Initial proposed burialhistory model for Well #1. The model includes an extensive nonerosional depositional hiatus.

B) Revised burial-history model for Well #1 based on the poor correlation with measured maturity data. 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. In actuality, time data are seldom a problem. First, the dependence of maturity on time is linear, so even a rather large error in baking time will not produce a catastrophic change in maturity. Secondly, we usually have excellent control on rock ages through micropaleontology.

Age calls are often made within a million years, and can be even better in Cenozoic rocks. Only in cases where micropaleontological dating was not or could not be carried out, might we anticipate possible problems with time.

Temperature, in contrast, is the single most important cause of uncertainty and error in maturity calculations. The sensitivity of maturity to temperature is clearly indicated by the exponential

dependence of maturity on temperature predicted by the Arrhenius equation.

Family of burial-history curves for a well in the Big Horn Basin, Wyoming; showing the evolution of the oilgeneration window through time. Tu = undifferentiated Tertiary; Tfu = Fort Union Formation; Km = Lance-Meeteetse formations; Kc = Cody-Frontier formations.(9-29)

Furthermore, our uncertainties about the true values of subsurface temperatures are much greater than about time. Present-day subsurface temperatures are difficult to measure accurately. Most logged temperatures are too low and require correction. Various methods have been developed for this purpose, but there is no guarantee of their accuracy in any particular case.

Predicting Thermal Maturity - 66

Even if we could measure present-day subsurface temperatures with perfect accuracy, however, we still would have to extrapolate the present somehow into the past. In many cases, where presentday temperatures are maximum paleotemperatures, even an inaccurate extrapolation into the past may not cause significant problems. In other cases, however, particularly where Paleozoic rocks are involved, an accurate interpretation of the ancient geothermal history may be critical. 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.

A question of some concern comes from the previously mentioned fact that most of the maturity models treat all types of kerogen identically. Despite experimental evidence indicating that different kerogens decompose to yield hydrocarbons at different levels of maturity models, do not utilize different kinetic parameters for the various kerogen types.

EXERCISES EXERCISE Thermal Maturity 1 Perform a source-rock evaluation of the section penetrated in the Turquoise Well.

Source-rock data tor the Turquoise Well Depth (ft)

Type of Sample

3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10,000

Cuttings Cuttings

TOC

Bit/TOC

Atomic H/C

1.0 0.8 0.7 0.9 1.1 2.3 2.6 4.1 0.5 0.3 1.8 1.7 0.2 0.4 0.3

0.06 0.06 0.05 0.08 0.91 0.66 0.22 0.51 0.08 0.08 0.27 0.18 0.01 0.03 0.02

0.90 0.85 0.86 1.02 0.91 1.25 1.21 1.17 0.65 0.71 0.99 1.03 0.60 0.51 0.48

TOC = Total Organic Carbon Bit/TOC = Bitumen/Total organic carbon ? indicates a poor histogram

Ro 0.49 0.52 0.59 0.65 0.67 0.88 0.91 1.00 1.07 1.27 1.21 1.26?

1.41?

1.33?

1.51

TAI

% Alginite + Exinite

2-2.5 2.5 2.5 2.5-3 2.5-3 2.5-3 2.5-3 2.5-3 3.0 3-3.5 2.5-3 2.5-3.5 3.5 3-3,5 3.5

40 30 35 40 50 80 75 75 25 40 70 80 20 15 10

TAI = Thermal Alteration Index Ro = Vitrinite reflectance

EXERCISE Thermal Maturity 2 The Black Well was drilled off the Louisiana Gulf Coast. It penetrated 1000 ft of Pleistocene sediments, 3500 ft of Pliocene, and 11,000 ft of Upper Miocene before being abandoned at 16,150 ft in the Middle Miocene. The corrected bottom-hole temperature was 270째 F. A plausible average surface temperature is 20째 C. Construct a family of burial-history curves for the well and calculate the present-day TTI at total depth.

Base Pleistocene 2 Ma Base Pliocene 5 Base Upper Miocene 11 Base Middle Miocene 50 Ma

Predicting Thermal Maturity - 67

EXERCISE Thermal Maturity 3 Calculate present-day TTI at 3000 m in the Red Well, assuming a constant geothermal gradient through time. Find when the rock at 3000 m began to generate oil (TTI = 10). Determine when each of the strata began to generate oil.

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.

Corrected BHT (4200 m): Estimated surface temp.end Cretaceous:

15° C 141° C 25° C

EXERCISE Thermal Maturity 4 The Ultraviolet Well is spudded in Paleocene sediments. At a depth of 1500 ft, 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. Total depth is reached at 6120 ft in Middle Jurassic rocks.

Evidence from related sections indicates that the Paleocene was originally about 3000 ft thick and that no other Cenozoic sediments were ever deposited. Total original thickness of the Kimmeridgian is thought to be 1500 ft. It is also believed that 500 ft of Lower Cretaceous sediments were deposited before uplift and erosion began.

Assuming a surface temperature of 10° C and a geothermal gradient of 2° F/100 ft, draw a burial-history curve for the section penetrated and calculate maturity for the Kimmeridgian shale.

Age data top Paleocene base Paleocene base Maastrichtian base Campanian base Santonian base Coniacian

55 Ma 65 73 83 87.5 88.5

base Turonian base Cenomanian base Cretaceous top Kimmeridgian base Kimmeridgian

91 Ma 97 144 150 156 Ma

Predicting Thermal Maturity - 68

EXERCISE Thermal Maturity 5 Analyze the timing of oil generation in the Pink Well. The geothermal gradient was found to be 1.0째 F/100 ft, and the surface temperature today is about 15째 C. Time-stratigraphic data are given in the following table. No unconformities are recognized within the Paleozoic. Erosional removal since the Permian probably totals about 2000 ft.

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. Carboniferous '' '' '' '' E. Carboniferous '' Ordovician ''

Depth (ft) 7,000 8,000 11,000 13,000 18,500 21,000 23,000 25,500 27,500

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. Because of the high operations cost, upper management has decided that gas and condensate are not economical. Your responsibility is to make a recommendation regarding the nature of hydrocarbons that might be present in die prospect. The following geological summary is available to you.

"A regional study of the area suggests the probable presence of a thin, rich, oil-prone source rock at about 4300m depth near the prospect. The source rock is thought to be about 300 Ma old. No other source rocks were noted. Highly fractured carbonates overlie the source rock; they are in turn overlain at 2750m by a sandstone of excellent reservoir quality. The reservoir is sealed by a thick salt layer. No other reservoirs are anticipated.

The basin filled at a generally uniform rate from about 300 Ma to 100 Ma. At that time nearby orogenic activity caused the first traps to be formed during a gradual 1200m uplift lasting until 40 Ma. From 40 Ma to the present about 500m of additional burial occurred.

Nearby well control indicates that a geothermal gradient of 3.65째C/100 m and a surface intercept of 15째C are reasonable for the area. 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."

Utilizing the principles of hydrocarbon generation and preservation, evaluate the prospect.

Quantitative Assessment - 69

10 - Quantitative Assessment So far we have been talking in rather generalized terms. However, we have to remember that we are dealing with a resource and that we are very concerned with the quantities involved. Now we must see how we can apply our knowledge of the geology to assessing the amounts of petroleum that we have found, or hope to find. This section is included to give an idea of what is involved. We will refer to oil, but the same considerations, methods, and terms can be used equally for gas.

First, let us again emphasize that we are dealing all the time with uncertainties. 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, let alone how much. And yet oil companies need to know what to expect.

Similarly, once a discovery is made, there is no way that we can know precisely how much we have found: the geology, which controls the amounts of oil in the reservoir, is liable to change between our information points, our wells. We have to try to understand, or predict, just what these changes amount to. So, until actually all of the oil has been produced, we are involved with a greater or less degree of uncertainty about quantities. How do we handle these problems?

Before we get into this, we have to clear a good deal of misunderstanding and misuse, even within oil companies, of the following terms:

OIL IN PLACE This is the total volume of oil, measured in barrels or other units that is present in an accumulation under the ground. It usually refers to what was there originally, before we started to take any of it out. You may see the engineers using the term STOOIP: stock tank oil originally in place. The stock tank is, in the case of small fields, located at surface near the well-head, and oil may be produced directly into it; 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, and therefore without any dissolved gas of significance. We cannot regard these quantities as `reserves', since we are never able to recover all of the oil that is down there in the reservoir.

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.

Recoverable reserves: The volume of oil that can actually be produced to surface from an accumulation. We may distinguish between primary reserves that can be produced without any artificial assistance other than pumping; secondary reserves, which can be produced using assisted or enhanced recovery techniques; and tertiary reserves using more exotic techniques. Note, however, 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. A bald figure for `recoverable reserves' is somewhat meaningless, unless we can be more specific about how we are going to produce them.

Because anyway there is uncertainty about this amount, it is desirable to be able to express our degree of confidence in it. This may be done via a standard deviation or by a statistical probability (see below).

Proven reserves: Here we start to enter a minefield! Different companies have different definitions of what is proven. Some might use the term to refer to the amount of recoverable oil that is believed to lie within a given radius, half a mile or whatever, of a well, What they think is beyond that in the accumulation, they might designate as `probable'. Increasingly these days, companies tend to use `proven' for those reserves that are believed to be present with an 85 or maybe 90 per cent degree of

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confidence or statistical probability. What this means and how we arrive at the figure, we shall see shortly.

Probable reserves: Equally dodgy! One definition was given above: the term may be used, like `proven', to refer to a degree of confidence or probability, in this case 50 per cent. Sometimes `possible' is also seen, to cover the reserves that have only a 15 or 10 per cent chance of being present. It may well be that it is best to avoid the terms `proven', `probable', and `possible' altogether, 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. They refer respectively to what was there and recoverable before we started producing, and what is still there for the taking at a given date. Usually, if we hear simply about `reserves', it is the remaining reserves, that are meant.

DISCOVERED RESERVES Once a discovery of oil has been made, 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. We then eliminate progressively everything from this volume that is not oil. So we multiply the bulk volume of the reservoir in the trap by those factors that represent the non-oil.

Recoverable reserves = [BV * Fill * N/G * ? * (1 - Sw)] * RF * Constant FVF where: – BV is the volume of the reservoir formation within the closure of the trap above the spill-point.

The shape of the trap, faulting, and the thickness of the reservoir govern it. BV will be determined from seismic and well data, and regional and local geological interpretation.

– Fill is the `fill factor', which is the percentage of the bulk volume that actually contains the oil, the volume of the gas cap and the water-bearing rock below the oil-water contact being discounted. It is affected by many factors, including the adequacy of the source rock to provide enough oil to the trap, and the quality and strength of the cap rock. If we do not know where the gas-oil and oil-water contacts are, then this factor may be little more than a guess; if we do, then we can go straight to the bulk reservoir volume containing the oil.

– N/G is the net to gross ratio. Not all of a reservoir formation is going to be sufficiently porous and permeable to contribute oil to production. We have to discount those parts of it that are useless and just consider the net reservoir thickness. This will be controlled by variations in the nature of the sediments that comprise the reservoir, meaning that we have to try to interpret in detail the environments that the sediments were deposited in. This can be pretty subjective, even when we have information from a lot of wells. What anyway should we regard as net reservoir?

A rather arbitrary porosity cut-off value is often used.

– ? is the porosity, or rather the average porosity of the net reservoir across the entire accumulation. We do our best from measurements on core samples and from wireline log interpretation, but what happens between and beyond our well control?

– Sw is the water saturation, the percentage of the porosity that is occupied by the immovable water. Again we need an average value for the field. 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, the higher will be the water saturation.

– 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; it shrinks because gas bubbles out of it as its pressure is eased during production. 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.

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RF is the recovery factor, the proportion of the oil in the reservoir that we can actually recover and produce. In a sandstone reservoir, this is commonly about 50-60 per cent, but it may be a good deal less from carbonates. It is a figure that we cannot know exactly until we have finished producing. So we usually have to base our estimate on prior experience elsewhere.

A constant is needed to adjust the units. The Americans measure reservoir volume in acre-feet: area in acres multiplied by reservoir thickness in feet. To get an answer to our sum in barrels of oil, we have to multiply the figure we calculate by 7758. If we are working entirely in the metric system, then we don't have to worry.

It will be clear to anyone that, in producing figures for all of these factors, there must be considerable uncertainty to say the least. What we are doing, then, is to multiply uncertainties by uncertainties, doubtful estimates by doubtful estimates, until we begin to wonder whether our answer has any reality or meaning at all. Different geologists will certainly come up with different values for at least some of the input factors, and arrive at perhaps wildly different answers. Who is right?

Whose answer should we use? Can we indeed believe any of them? Unfortunately we cannot escape from the problem; companies, and governments must have numbers that they can use for planning purposes, even though they may be well aware that any such figures will eventually turn out to be wrong.

Most commonly these days, and to try to be as honest and objective as possible, the problem is tackled through a statistical technique, known as a Monte Carlo simulation.

Instead of estimating single figures for the factors that go into the reserves formula, for each of the factors we work out our best estimate, having regard to all of the geology; and we also specify the total range, from minimum possible to maximum possible, somewhere within which the `true' figure must be. Then we get a computer to pick a value for each factor at random from the range we have given, but biassing its pick towards our best estimate. The computer does the sum using these values. Then we ask it to do the same thing again, and again, and again... maybe 500 or 1000 times.

So we have a whole list of answers, any one of which could be the real value. The list is put into order from the smallest to the largest, and then analysed statistically.

If we plot out the answers on our list falling within successive size ranges (in barrels of oil), we shall find that the bulk of them tend to cluster round the middle (Fig.). 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, our best estimate. More commonly, however, we give as our preferred figure the average of all the answers (the mean).This is because, for this average value, we can work out the standard deviation (the Âą) which will give an idea of our confidence in our answer.

Diagrammatic plots of the outputs from two Monte Carlo simulations. The number of answers in successive reserve ranges is plotted against the size ranges themselves. Alternatively one may plot the frequencies as percentages of the total number of answers: the statistical probabilities. Note that the preferred answer that is usually used is the mean value, since it is about this that the standard deviation can be calculated.

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The output from a Monte Carlo simulation with the percentages plotted cumulatively. By plotting the answers from the 100 per cent probability downwards, the curve represents the chance (probability) that the reserves are a certain size or greater. In the lower plot, the same values are discounted by a 50 per cent risk factor, to give the chance of discovering certain reserves or more including the 50 per cent chance that we may find nothing at all.

Most usefully, perhaps, we can plot out the percentages of answers in successive size ranges cumulatively as we work down the list (Fig.). It will give a graph which shows the probability that the reserves will be of a certain size or more. This is what is used to determine those reserves that may be called proven, probable, and possible at, say, the 90, 50, and 10 per cent levels of probability respectively. It is also used to assist management in making their exploration/development decisions.

For example, if the engineers say that a field of so many million barrels is going to be needed to justify development and production costs, we can read off from the graph the chances of our field containing that much oil or more; management can then decide whether or not to take the gamble on developing the field at those odds. So this type of graph has now become one of the standard key tools in exploration/development decision.

UNDISCOVERED RESERVES This is all very well, you may say, but it assumes that we have already discovered oil; it doesn't take any account of the fact that our exploration well may, for geological reasons, turn out to be totally dry-lacking in hydrocarbons. Indeed it does not! When we are looking at exploration of the unknown, as opposed to assessing what we already know to be there, we have to go a stage further.

We have to give not only our best estimate of how much petroleum there might be, but also the chance of there in fact being any oil at all. This chance (probability) is known as the risk factor: it is an expression, in numbers, of our confidence that there will be at least some oil. The risk factor, combined with the estimate of how much, now gives a more complete picture of the viability of an undrilled prospect - at least until we start also considering the costs and economics.

When it comes down to risk, there really is no such thing as the risk factor. It cannot be worked out completely objectively, but rather it is the number an individual geologist might produce to reflect his/her personal interpretation of the geology; different geologists will arrive at different figures for the probability of success. And if all this sounds like a gambling game, that is exactly what it is. It is this sort of thing that helps to make the oil exploration business so competitive.

Of course we try to be as scientific, objective, and honest as can be in assessing exploration risk. 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, if any one of them fails or is lacking, then no oil. We try to assess the probability that each factor will be satisfied, and then merely combine the probabilities to give an overall probability - the risk factor.

Incidently, 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, and ensures that all possibilities are considered.

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Lastly, on this tack, let us note a number known as the risked reserves, the expected reserve estimates from our Monte Carlo simulation multiplied (discounted) by the risk factor (Fig.). This combines in a single estimate, the two elements of size and chance of success, and as such can be very useful in planning an exploration program. Should we, for example, go for a large but very risky prospect, or would our money be better spent on drilling a smaller but safer one? The risked reserves, however, is a hypothetical figure, 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.

Undiscovered are thus what we hope to find in a prospect area or sedimentary basin in the future.

This figure is extremely imprecise and may be not much more than a guess; we can, however, qualify it by a statistical probability. Adding this to the original reserves will give us what is sometimes called the `ultimate reserves'-a grand total for the basin.

ULTIMATE RESERVES So far we have been talking about a single oil accumulation or a single prospect. 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.

Many `experts' have scratched their heads over the estimation of undiscovered reserves, and a number of techniques have been employed. Let us look at the more important ones.

1. The obvious thing to do is to add together the risked reserves estimates of all the remaining prospects. Some of these will be successful, but some will be dry; the built-in risk factor takes care of this. However, we have to assume that today we can identify and assess all of the prospects that ever will be found in the basin; to believe that we can do this would be the height of conceit.

2. We could adopt what is known as a `geochemical material balance' approach. This starts with the volume of mature source rock in the basin and then, knowing how rich it is, the amount of oil generated, expelled, and made available for entrapment (the `charge') can be calculated. There are lots of uncertainties in this but the calculation would be amenable to a Monte Carlo type of simulation. If we have a reasonable amount of information and control, this technique may bring us into the right ball-park; otherwise we may be doing little more than guessing.

3. We might look at explored and known parts of the basin, and calculate average quantities of oil per cubic mile of sediment, or underlying each square mile of surface area; then use these figures for the unexplored parts of the basin.

4. We could make comparisons between known and unknown basins, and use the figures for the known also for the unknown ones.

5. Use past statistics (number of barrels of oil found on average for each 100m of exploration drilling?) and extrapolate to future drilling. In a similar vein the amount of oil found world-wide each year from the beginning of the century can be plotted; it is a pretty wild sort of plot.

However, if we draw a smooth line through it to even out the peaks and the troughs, then the area under it represents the total volume of oil found to date. Extrapolate this smoothing line out into the future, and the area under that bit will represent what, on average, remains to be found.

This kind of plot can be used also for individual basins or for the whole world.

6. If all else fails, get a number of experts to make their forecasts by whatever technique they prefer and, for our `best estimate', merely use the average of the figures they produce. Forcing these experts to agree a figure amongst them might refine the approach. This is known as the Delphi technique. Delphi was the place in ancient Greece where one went to consult the oracle about one's future; we are said to be consulting the oracles!

All of the above techniques have been used, sometimes in combination, and some may be more appropriate in given circumstances than the others. But we have to admit that, unless we really have a lot of information (we never have enough!), all of them are very dodgy