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. 151pp.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 ....................................................................................................................... 6FACTORS INFLUENCING ORGANIC RICHNESS............................................................................ 7

PRODUCTIVITY .............................................................................................................................. 7PRESERVATION.............................................................................................................................. 8DILUTION ..................................................................................................................................... 11

SUMMARY ....................................................................................................................................... 12

3 - ORGANIC CHEMISTRY .............................................................................................................. 13

INTRODUCTION.............................................................................................................................. 13NAMES AND STRUCTURES........................................................................................................... 13

HYDROCARBONS ......................................................................................................................... 13NONHYDROCARBONS ................................................................................................................. 15

4 - KEROGEN...................................................................................................................................... 17

INTRODUCTION.............................................................................................................................. 17KEROGEN FORMATION................................................................................................................. 17KEROGEN COMPOSITION ............................................................................................................. 18KEROGEN MATURATION.............................................................................................................. 20

INTRODUCTION ........................................................................................................................... 20EFFECTS OF MATURATION ON KEROGENS ............................................................................. 21HYDROCARBON GENERATION................................................................................................... 22

SUMMARY ....................................................................................................................................... 23

5 - BITUMEN, PETROLEUM, AND NATURAL GAS...................................................................... 24

INTRODUCTION.............................................................................................................................. 24COMPOUNDS PRESENT IN BITUMEN AND PETROLEUM ......................................................... 24

GENERAL CLASSES OF COMPOUNDS ....................................................................................... 24SPECIFIC COMPOUNDS.............................................................................................................. 25

FACTORS AFFECTING COMPOSITION OF BITUMEN AND PETROLEUM................................ 25SOURCE AND DIAGENESIS ......................................................................................................... 25RESERVOIR TRANSFORMATIONS............................................................................................... 26COMPARISON OF BITUMEN AND PETROLEUM ....................................................................... 27NATURAL GAS .............................................................................................................................. 28

SUMMARY ....................................................................................................................................... 28

6 - MIGRATION.................................................................................................................................. 29

DEFINITIONS................................................................................................................................... 29PRIMARY MIGRATION................................................................................................................... 29

MECHANISMS............................................................................................................................... 29DISTANCE AND DIRECTION ....................................................................................................... 30

SECONDARY MIGRATION............................................................................................................. 31MECHANISM................................................................................................................................. 31

Contents

DISTANCE AND DIRECTION ....................................................................................................... 31ACCUMULATION............................................................................................................................ 32

INTRODUCTION ........................................................................................................................... 32CLASSICAL TRAPS........................................................................................................................ 33KINETIC TRAPS ............................................................................................................................ 33TAR-MAT TRAPS ........................................................................................................................... 34GAS HYDRATES ............................................................................................................................ 34

EFFECTS ON OIL AND GAS COMPOSITION ................................................................................ 34SIGNIFICANCE FOR EXPLORATION ............................................................................................ 35

7 - PETROLEUM TRAPS ................................................................................................................... 36

THE REPRESENTATION OF TRAPS .............................................................................................. 36STRUCTURAL TRAPS ..................................................................................................................... 37STRATIGRAPHIC TRAPS................................................................................................................ 41COMBINATION TRAPS................................................................................................................... 42HYDRODYNAMIC TRAPS .............................................................................................................. 43THE RELATIVE IMPORTANCE OF TRAPS ................................................................................... 43EXERCISES ...................................................................................................................................... 45

8 - SOURCE-ROCK EVALUATION.................................................................................................. 49

DEFINITION OF SOURCE ROCK.................................................................................................... 49PRINCIPLES OF SOURCE-ROCK EVALUATION .......................................................................... 49

QUANTITY OF ORGANIC MATERIAL .......................................................................................... 49MATURITY OF ORGANIC MATERIAL.......................................................................................... 49CONTAMINATION AND WEATHERING....................................................................................... 52ESTIMATION OF ORIGINAL SOURCE CAPACITY ...................................................................... 52

INTERPRETATION OF SOURCE-ROCK DATA ............................................................................. 53QUANTITY OF ORGANIC MATERIAL .......................................................................................... 53TYPE OF ORGANIC MATTER....................................................................................................... 53MATURITY..................................................................................................................................... 54COALS AS SOURCE ROCKS ......................................................................................................... 54

SUMMARY ....................................................................................................................................... 55EXERCISES ...................................................................................................................................... 56

9 - PREDICTING THERMAL MATURITY ...................................................................................... 60

INTRODUCTION.............................................................................................................................. 60CONSTRUCTION OF THE GEOLOGICAL MODEL ....................................................................... 60

BURIAL-HISTORY CURVES.......................................................................................................... 61TEMPERATURE HISTORY............................................................................................................ 61SPECIAL CONSIDERATIONS ABOUT BURIAL-HISTORY CURVES ............................................ 62

CALCULATION OF MATURITY..................................................................................................... 63FACTORS AFFECTING THERMAL MATURITY............................................................................ 64POTENTIAL PROBLEMS WITH MATURITY CALCULATIONS..................................................... 65

EXERCISES ...................................................................................................................................... 66

10 - QUANTITATIVE ASSESSMENT ............................................................................................... 69

OIL IN PLACE .................................................................................................................................. 69RESERVES........................................................................................................................................ 69

DISCOVERED RESERVES............................................................................................................. 70UNDISCOVERED RESERVES ....................................................................................................... 72ULTIMATE RESERVES.................................................................................................................. 73

Organic Facies - 5

1 - Introduction

FORMATI0N OF 0IL AND GASProponents of the organic origin of oil and gas have given us a general picture of how organic matterderived from dead plants is converted to hydrocarbons. Although the transformation process is verycomplex, with many details still poorly understood, it is known that organic debris derived fromplants 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 transportto and early burial in the depositional environment modify this organic matter. Many of the chemicalcompounds present in sediments are in fact derived from bacteria, and were formed as dead organicmatter was converted to microbial tissues.Most of this organic matter is transformed during diagenesis info very large molecules, the largest ofwhich 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 biogenicmethane has been recognized for a long time, but only within the last few years have we realized thatin many areas a large portion of the natura!-gas reserves are biogenic.As burial depth increases, porosity and permeability decrease, and temperature increases. Thesechanges lead to a gradual cessation of microbial activity, and thus eventually bring organicdiagenesis to a halt. As temperature rises, however, thermal reactions become increasinglyimportant. During this second transformation phase, called catagenesis, kerogen begins todecompose into smaller, more mobile molecules. In the early stages of catagenesis most of themolecules 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, calledmetagenesis, the principal products consist of smaller gas molecules.In recent years this relatively simple picture of hydrocarbon generation has been complicated slightlyby our growing awareness that kerogens formed from different kinds of organic matter, or underdifferent diagenetic conditions, are chemically distinct from each other. These differences can have asignificant effect on hydrocarbon generation.Once formed, oil and gas molecules can be expelled from the source rock into more permeablecarrier beds or conduits. Migration through these conduits often leads to traps, where hydrocarbonmovement ceases and accumulation occurs.

Organic Facies - 6

2 - Organic Facies

THE CARBON CYCLEBecause oil and gas are generated from organic matter in sedimentary rocks, we need tounderstand how this organic matter came to be preserved in the rocks. Preservation of organicmaterial is actually a rare event. Most organic carbon is returned to the atmosphere through thecarbon cycle; less than 1% of the annual photosynthetic production escapes from the carboncycle and is preserved in sediments. Oxidative decay of dead organic matter is a highly efficientprocess mediated largely by microorganisms.Preservation of organic matter begins with photosynthesis. Some of the organic material insediments consists of fragments of plants or algae that derived their energy from the sun. A largefraction, however, comprises microbial tissue formed within the sediments by the bacterialtransformation of plant and algal debris. Zooplankton and higher animals contribute relativelylittle organic matter to sediments. The recently discovered deep-sea ecosystems in the PacificOcean 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]) andaquatic phytoplankton (5 billion t), the yearly productivity of both groups is about equal, as aconsequence of the much more rapid reproduction of simple aquatic organisms. Because of

Organic Facies - 7

extensive oxidation of land-plant debris in soils, however, much of the terrestrial organic materialis already highly oxidized when it arrives in the sediments.Although some destruction of organic material occurs during transport to the depositionalenvironment, a great deal of the oxidation of organic matter occurs within the sedimentsthemselves. Total Organic Carbon (TOC) values decrease monotonically through the first 300meters of burial before levelling out at about 0.1%, suggesting that either depth or organic-carbon content eventually limits diagenesis. Depth could interfere with microbial diagenesis whencompaction reduces pore sizes and nutrient fluxes in interstitial waters. On the other hand, thelow 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 underdifferent conditions.Although oxidative decay destroys most of the yearly production, over vast amounts of geologictime the small fraction that escaped the carbon cycle has built up extremely large quantities oforganic matter (20,000,000 billion t) dispersed in fine-grained sedimentary rocks. Only a smallfraction 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 everyone million successfully negotiates the journey from living organism to the gasoline pump.

FACTORS INFLUENCING ORGANIC RICHNESSIn order for organic-rich rocks to be formed, significant amounts of organic matter must bedeposited and protected from diagenetic destruction. The three primary factors influencing theamount 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.

PRODUCTIVITYA partial listing of the many factors influencing productivity would include nutrient availability,light intensity, temperature, carbonate supply, predators, and general water chemistry. Each ofthese categories could in turn be further subdivided. For example, nutrient availability woulddepend 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. Shallow-marine environments, where there is local recycling of nutrients from decaying organisms andinflux of fresh nutrients from terrestrial sources, are therefore much more productive than theopen ocean.In relatively unrestricted marine environments, watercirculation patterns are particularlyimportant for supplying nutrients and thus controlling productivity. Bodies of water naturallydevelop density stratification, with a preference for horizontal water movement within eachdensity 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 allowsdeeper water to ascend to replace it. If this deeper water is enriched in nutrients, highphotosynthetic productivity will occur at the site of upwelling. In the modern world there arezones of intense seasonal upwelling off the west coasts of California, Peru, Namibia, andNorthwest Africa that result from the movement of surface waters away from these coasts. Thereis another zone of seasonal upwelling off the Horn of Africa in the Indian Ocean as a result of

Organic Facies - 8

monsoonal winds that drive surface waters away from the coast. All these areas exhibit highproductivity when upwelling occurs.Theoretical models have been developed to predict upwelling (and consequent productivity) inancient seas from input data on continental configurations, landmasses, wind and watercirculation 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 asimportant a factor as preservation. There are many more organic-rich facies resulting fromexcellent 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 increaseorganic richness. Secondly, the accuracy with which we can reconstruct continental positions,paleoclimatic conditions, and all the other factors that influence upwelling loci is severelylimited, especially in the Palaeozoic.

PRESERVATIONThe principal control on organic richness is the efficiency of preservation of organic matter insedimentary environments. Three factors affect the preservation (or destruction) of organicmatter: 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 crucialfactor.

ANOXIA. Because most of the oxidation occurring in the water column, soils, and sediments isbiological, and because most biological oxidation processes require molecular oxygen, thesimplest way to limit oxidation is to limit the supply of oxygen. All large organisms requireoxygen in order to live, although some species can tolerate extremely low oxygen levels (0.5milliliters (mL) per liter (L)). At lower levels of dissolved oxygen, many species disappear; theremaining individuals often become dwarfed in an effort to survive in a hostile environment. Atdissolved oxygen levels below about 0.2 mL/L, essentially the only viable organisms are thosethat we call anaerobes, microorganisms that utilize materials like sulfate or nitrate ions insteadof 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 fallsbelow 0.2 mL/L is called the anoxic zone. Processes that occur in these two zones are calledaerobic and anaerobic, respectively. The term dysaerobic has been used to describe processesoccurring in the transitional zone (0.2-0.5 mL/L), and we could coin the term dysoxic to describethe zone itself. The term "anoxic" literally means "having no oxygen," hut because of the radicalchange in biota that occurs at about 0.2 mL/L, its use in practice has been expanded to includevery low oxygen levels as well.Anoxia is of tremendous importance in the preservation of organic matter in sediments, becausewhen the availability of oxygen is limited, diagenesis is restricted to anaerobic processes. Theseanaerobic processes are inefficient compared with aerobic diagenesis, and are usually limited inscope by the availability of sulfate or nitrate. Thus if anoxia can develop, preservation of organicmatter will be much enhanced.Anoxic sediments are not always easy to recognize, because some of the commonly usedindicators 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 largeamounts of organic matter, especially of woody origin. TOC values alone must therefore be usedwith caution. The presence of undegraded marine organic material is a strong indication ofanoxia, because marine organic matter is consumed preferentially by organisms. Its presence in

Organic Facies - 9

rocks therefore indicates that diagenesis was stopped prematurely, most likely by absence ofoxygen.Color is not a reliable indicator. All anoxic sediments will be very dark gray or black whendeposited. Many black rocks, however, are not rich in organic carbon; they often owe their darkcolor to finely divided pyrite or to particular chert phases. Color should be used mainly as anegative 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 underanoxic 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 afterburial. Furthermore, anoxia can be very local; intense pyritization of benthic bivalves istestimony to the fact that pyrite is not a good indicator of bottom-water anoxia at the time ofdeposition.Finally, anoxic sediments show preserved depositional laminae on a millimeter or submillimeterscale. The laminae prove that burrowing fauna were absent, and therefore that dissolved-oxygenlevels were below 0.2 mL/L. Conversely, the presence of bioturbation indicates that the bottomwaters 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, infact, that most of the world's oil was generated from source beds deposited under anoxicconditions. It therefore behoves us to understand the conditions under which anoxia develops.

STAGNANT BASINS. Truly stagnant basins are actually quite rare; slow circulation orturnover of the water column occurs almost everywhere. Nevertheless, it is instructive toconsider complete stagnation, particularly in understanding lacustrine beds. If an isolated body ofwater is deep enough, and if the climate is subtropical or tropical, then permanent densitystratification will arise as a result of temperature differences within the water column. Depths inexcess of 200 m are required to prevent mixing during storms, and warm climates are necessaryto 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 preventsinterchange between the two layers. Lack of communication between the layers prohibitsreplenishment of oxygen in the bottom layer. Therefore, once the original oxygen has beenconsumed in oxidizing organic matter, no more oxygen can enter, and both the waters in thebottom layer and the underlying sediments will become anoxic.Marine basins are seldom isolated enough to fit well into the stagnant-basin model, but limnicenvironments often are. Among the ancient lake beds thought to have been deposited inpermanently 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. Lakedeposits associated with continental rifting, especially during the Triassic along the margins ofthe 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 ofEast Africa are excellent modern analogs receiving much attention from both researchers andexplorationists at the present time.

OXYGEN-MINIMUM LAYER (OML). The oxygen-minimum layer is a layer of subsurfacewater 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 layerexceeds the rate of influx of oxygen to it. Consumption of oxygen results from decay of deadorganisms that have sunk from the photic zone above. The oxygen minimum layer usually beginsimmediately below the photic zone, where photosynthesis and turbulence can no longercontribute oxygen to the water. The supply of fresh oxygen is therefore limited to horizontal

Organic Facies - 10

movement of oxygen-bearing waters. However, because these horizontally moving waters also liewithin the oxygen minimum layer, the oxygen they can contribute is limited. Below the OMLoxygen levels again increase, as a result of diminished oxygen demand, since most organic matterwas destroyed within the overlying OML.Although an oxygen-minimum layer exists virtually everywhere in the ocean, its intensity variesgreatly. Intensely developed OMLs occur in areas of high productivity and, to a lesser extent, inareas of poor circulation. Wherever an intensely developed OML intersects the sediment-waterinterface, sediments will be deposited under low-oxygen conditions. Any organic matter arrivingin 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 arelaid down within a well-developed oxygen-minimum layer. In contrast, foreset beds within thesame 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 ornear-anoxic conditions associated with OMLs. These include the modern Peru-Chile shelf (highproductivity associated with upwelling) and occurrences of black sediments of Aptian toTuronian age in the North Atlantic.It has been proposed that at certain times in the past (e.g., mid-Cretaceous, Late jurassic, LateDevonian) the world oceans were severely depleted in dissolved oxygen. This depletion wasprobably the result of the complex interplay of several factors, including paleoclimate and watercirculation. During those times the OML expanded both upward and downward because of poorsupply of oxygen to subsurface waters. In times like the mid-Cretaceous, when a majortransgression had greatly increased the continental shelf area, an upward expansion of the OMLled to a tremendous increase in the surface area covered by anoxic bottom waters. It is notcoincidental that these were times of deposition of large amounts of organic-rich rocks in manyparts of the world.

RESTRICTED CIRCULATION. Settings in which circulation is restricted are much morecommon than stagnant basins. Furthermore, because of their connection with the open-marinerealm, 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 connectionbetween the restricted area and the open-marine environment. Where the sill is shallow, thewaters entering or leaving the basin are near surface. In an evaporitic environment (Karabogaz inthe Caspian Sea) there is a net flow of water into the basin, whereas in a fluvially dominatedsystem (Black Sea) the net flow of surface water is out over the sill. In either case, if the basin isdeep enough, permanent density stratification will develop, with the bottom layer almost isolatedfrom the open-marine waters. In actuality there is a lazy turnover of the bottom waters, but it istoo slow to disturb the anoxia which develops in the bottom layer.Shallowly silled basins often yield evaporites, which could be excellent hydrocarbon sourcerocks. Evaporitic environments combine the opportunity for abundant growth of algae with idealconditions for preservation. Nutrients are concentrated by evaporation, and grazers andpredatory organism are eliminated by the high salinities. High productivity reduces oxygenlevels, and high hydrogen-sulfide concentrations create conditions poisonous to predators. Theresult is often deposition of organic-rich laminae within evaporites, or as lateral faciesequivalente thereof.Coal Swamps. Large amounts of organic material are preserved in coal swamps as a result ofthe combined effects of poor water circulation, high influxes of organic matter, and diminishedbacterial activity. Coal swamps can develop under a variety of conditions in both marine andnon-marine environments. Although circulation in coal swamps is generally sluggish, theshallowness of the swamps prevents the waters themselves from becoming anoxic. Anoxia

Organic Facies - 11

develops within the sediments rather than in the water column. Phenolic bactericides derivedfrom lignin hinder bacterial decay in the water and throughout the sediment column. Lack ofsulfate in non-marine swamps further prevents anaerobic microbial destruction of the organicmatter.Coals are important source rocks for gas accumulations, but their supposedly low potential forgenerating oil is to be reconsidered.Oxic Settings. Most depositional settings not specifically catalogued above will be more or lesswell oxygenated, and therefore wi11 contain primarily oxidized organic matter. Near-shoreoxidizing facies sometimes have high TOC values, but the organic material is almost invariablywoody. Abyssal sediments are notoriously low in organic carbon as the result of the combinedeffects of high oxygen levels in abyssal waters, very slow sedimentation rates, and lowproductivity in the overlying pelagic realm. The hydrocarbon-source potential of all of theseoxidizing facies is low, and more favorable for gas than for oil.

TYPE OF ORGANIC MATTER. Organic matter of algal (phytoplanktonic) origin isconsumed more readily by organisms than are other types of organic material, because itschemical components are digestible and provide precisely the nutrients required by scavengersand predators. Nitrogen and phosphorus are in particular demand; their virtual absence in muchterrestrial organic material, especially in structural (woody) material, renders it of littlenutritional value. Furthermore, the phenolic components present in lignin-derived terrestrialmaterial are toxic to many micro-organism, thus preventing extensive diagenesis of suchmaterial.Any extensive organic diagenesis is therefore likely to eliminate algal organic matter first. Thatmaterial 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, forestfires, and other oxidative processes.

RAPID SEDIMENTATION AND BURIAL. Rapid sedimentation and burial con also enhancepreservation. TOC values increase as sediment-accumulation rates increase, as a result of morerapid removal of organic material from the zone of microbial diagenesis.Rapid burial is accomplished by a high influx of inorganic detritus, biogenic inorganic sediment, ororganic material. Rapid deposition of inorganic detritus is common in turbidites and in prodeltashales. The extremely high accumulation rates for biogenic carbonates and siliceous sediments inzones of high productivity promote preservation of the associated algal protoplasm. Coals alsoaccumulate very rapidly and, with their high concentrations of organic matter, provide an idealmeans of maintaining low-oxygen conditions.Rapid settling of organic debris through the water column is also important, because extensivedecomposition occurs during its fall to the ocean floor. In fact, much of the organic material thatdoes reach the bottom in deep waters arrives in relatively large fecal pellets, which settle severalorders of magnitude faster than individual phytoplankton.

DILUTIONAlthough high sediment-accumulation rates enhance preservation of organic matter, at very highaccumulation 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 thatorganic material through a larger volume of rock. The net result is a reduction in TOC values.

Organic Facies - 12

Dilution effects depend upon rock lithology. Biogenic sediments, in which the organic andinorganic 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 fromcarbonates to shales may create large dilution effects that can be wrongly interpreted asindicating changes in oxygen levels.

SUMMARYThere are three principal factors that affect the amount of organic matter in sedimentary rocks:primary photosynthetic productivity, effectiveness of preservation, and dilution by inorganicmaterial. Of these, preservation is generally the most important.Productivity can be predicted by locating ancient sites of marine upwellings. Our ability to makeaccurate predictions is limited, however, by uncertainties about exact continental positions andconfigurations in the past, lack of knowledge of seawater chemistry and nutrient availability atthose 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 anumber of mechanisms by which oxygen depletion may be fostered and maintained, includingstagnancy or near-stagnancy, a strongly developed oxygen-minimum layer, and rapid burial. It isoften very difficult to separate the influences of these various factors in a particular depositionalenvironment.Rapid accumulation of sediment shortens the residence time of organic matter in the zone ofdiagenesis and thus promotes preservation. If the rapidly accumulating sediment is mainlyclastic, however, dilution effects may lead to lower TOC values in spite of enhanced preservationrates. In biogenic sediments or coals, in contrast, where sediment-accumulation rates are directlyproportional to organic-carbon-accumulation rates, dilution is far less marked.Because of its role in creating rocks with excellent hydrocarbon-source potential, anoxia inbottom 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 beable to distinguish local anoxia or anoxia developed deep within sediments from anoxia inducedby anoxic bottom waters. The most reliable criteria for bottom-water anoxia are the preservationof fine depositional laminae, and the presence of high TOC values coupled with the occurrence ofundegraded marine organic matter.Anoxic events in the past were probably not as large in scale or as long lasting as some workershave suggested. Although certain periods undeniably contain more than their share of anoxicrocks, anoxic sediments were deposited discontinuously through time and space. Direct control ofthe anoxia was thus probably local, as a result of high productivity or sluggish circulation. As inthe modern oceans, such events were often interrupted for long periods before anoxia wasreinduced.Models that integrate the concepts of organic richness with depositional cycles and faciesanalysis will be valuable tools for understanding hydrocarbon systems in basins. To derivemaximum value from our analyses, we should always strive to place the organic rich rocks in thelarger context of basin evolution through time and space.

Organic Chemistry - 13

3 - Organic Chemistry

INTRODUCTIONAnyone who uses petroleum geochemistry must be familiar with basic chemical terminology. Theobjective of this chapter is to acquaint the reader with the names of common compounds and withseveral different conventions for drawing their structures. This objective is very different trom thatof a normal course in organic chemistry, in which one must also learn all the reactions of manyclasses of compounds. The chemical reactions of interest to us are very few and are discussed onlybriefly. All compounds containing carbon atoms, except carbon dioxide, carbonates, and metalcarbides, are termed organic. This usage is historical and does not imply that all such compoundsare necessarily derived from living organisms. Organic chemistry is thus the study of carbon-containing compounds, and organic geochemistry the study of organic compounds present ingeological environments.

NAMES AND STRUCTURES

HYDROCARBONS

the term hydrocarbon to the standard chemical one; elsewhere in this text usage will vary, as it doesin the real world.

below.

In each of these compounds, and indeed in every carbon compound (except a few highly unstableones created only in laboratories), every carbon atom forms four bonds. Similarly, hydrogen alwaysforms one bond; oxygen and sulfer, two bonds; and nitrogen, three bonds. Carbon atoms like toform bonds with each other, creating long chains and ring structures. This unique property ofcarbon 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 hasto do it only occasionally. If one wants to draw large molecules, however, the explicit inclusion ofevery atom and every bond becomes extremely tedious. Several different types of shorthand havetherefore developed to facilitate drawing organic molecules.One common convention is to represent all the hydrogen atoms attached to a given carbon atom bya 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 representationsof n-pentane are equivalent: CH3CH2CH2CH2CH3 or CH3(CH2)3CH3.

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 isincorrect trom the chemist's point of view because those materials often contain substantial amountsof nitrogen, sulfur, oxygen, trace metals, and other elements. In this chapter we restrict the usage of

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

Organic Chemistry - 14

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

The zigzag configuration illustrated for n-pentane isadopted to show clearly each carbon atom.The simplest series of hydrocarbons has linear structures;these molecules are called n-alkanes or nparains. Theletter n stands for normal, and indicates that there is nobranching in the carbon chain. We have ahreadyencountered n-pentane; the names of the other ninesimplest 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, butthe prefixes denoting the number of carbon atoms in the other alkanes are derived from Greeknumbers.

Names and formulas of the ten smallest n-alkanesMethane 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, givingrise 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 2-methylhexane (C7H16) the basic structure is hexane; a CH3 (methyl) group is attached to the secondcarbon atom. Other adjectival forms are made by dropping the -ane ending and adding yl (forexample, 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 everyfourth carbon. Isoprenoids ranging in length from six to forty carbon atoms have been found inpetroleum and rocks.

We have also seen that carbon atoms can be arranged in rings. These cyclic compounds (callednaphthenes) are named by counting the number of carbon atoms in the ring and attaching the prefixcyclo.All the compounds mentioned above are called saturated hydrocarbons or saturates, because theyare saturated with respect to hydrogen. That is, no more hydrogen can be incorporated into themolecule without breaking it apart.Another important group of hydrocarbons is the unsaturates, which, in contrast, are able tocombine 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), andcyclohexene (C6H10), the structures of which are shown below. They are named in a similar mannerto 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 thelaboratory they are readily converted to alkanes by the addition of hydrogen in the presence of acatalyst. By hydrogenation ethene thus reacts to form ethane.

A variety of reactions, including hydrogenafion, converts alkenes to alkanes and cyclic compoundsduring diagenesis.Aromatics form an extremely important class of unsaturated hydrocarbons. At first glancearomatics appear to be nothing more than cyclic alkenes containing several double bonds, but theyactually 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 tobe important constituents of oils and sediments.Aromatics possess a system of alternating single and double bonds within a cyclic structure. Asimplified notation for drawing these molecules permits us to represent the double-bond system by acircle 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 twoparticular carbon atoms. It is this delocalization of electrons which makes aromatic compoundsvery stable.Some aromatic molecules are very large. Polycyclic aromatic hydrocarbons having fused ringstructures are quite common. The extreme case is graphite, which is an almost-endless sheet ofaromatic rings.The hydrocarbons we discussed so far are relatively simple molecules. Although they are veryimportant constituents of petroleum, these compounds are quite different trom the majority of theorganic molecules found in living organisms. Most biological molecules are larger and more

degradation of biogenic molecules. In fact, some complex hydrocarbons that are found in fossilorganic material can be related directly to individual biological precursors.

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

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

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

Organic Chemistry - 16

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

Many nonhydrocarbon molecules common to living organisms are also present in sediments. Amongthese 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 manyrepetitions and combinations of three basic aromatic subunits.Lignin monomers are linked topether to form molecules having molecular weights from 3000 to10,000 atomic mass units. Upon decomposition lignin forms phenolic compounds, which arearomatics having a hydroxyl group (OH) attached. Because phenols are potent bactericides, ligninis rather resistant to degradation, and thus tends to become concentrated as other organic matter isdecomposed.Carbohydrates include starch, sugars, and cellulose; the latter is the most abundant organiccompound 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 carbohydratesare 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 allorganisms, however, and thus are seldom preserved in sediments (exceptions occur in shell materialand in bones, where small amounts of preserved amino acids can be used to date specimens)

Kerogen - 17

4 - Kerogen

INTRODUCTIONKerogen is normally defined as that portion of the organic matter present in sedimentary rocks thatis insoluble in ordinary organic solvents. The soluble portion, called bitumen, will be discussed in afollowing chapter. Lack of solubility is a direct result of the large size of kerogen molecules, whichhave molecular weights of several thousand or more. Each kerogen molecule is unique, because ithas 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 ofbiogenic molecules from which the kerogen is formed and by diagenetic transformafions of thoseorganic 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 smallfragments of the kerogen as oil or gas molecules. The residual kerogens also undergo importantchanges, 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 thatwe exploit as fossil fuels. Diagenetic and catagenetic histories of a kerogen, as well as the nature ofthe organic matter from which it was formed, strongly influence the ability of the kerogen togenerate oil and gas. A basic understanding of how kerogen is formed and transformed in thesubsurface 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 oilupon retorting. Today it is used to describe the insoluble organic material in both coals and oilshales, as well as dispersed organic matter in sedimentary rocks. The amount of organic matter tiedup in the form of kerogen in sediment is far greater than that in living organisms or in economicallyexploitable accumulations of coal, oil, and natural gas.Coals are a subcategory of kerogen. Humic coals are best thought of as kerogens formed mainlyfrom landplant material without codeposition of much mineral matter. Algal (boghead) coals areformed in environments where the source phytoplankton lack both calcareous and siliceous skeletalcomponents. Oil shales, in contrast, have more mineral matter than algal coals, with some of theinorganic matrix often being contributed by the algae themselves. Coals and oil shales shouldtherefore be viewed merely as sedimentary rocks containing special types of kerogens in very highconcentrations.

KEROGEN FORMATIONThe process of kerogen formation actually begins during senescence of organisms, when thechemical and biological destruction and transformation of organic tissues begin. Large organicbiopolymers of highly regular structure (proteins and carbohydrates, for example) are partially orcompletely dismantled, and the individual component parts are either destroyed or used to constructnew geopolymers, large molecules that have no regular or biologically defined structure. Thesegeopolymers are the precursors for kerogen but are not yet true kerogens. The smallest of thesegeopolymers 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 geopolymersbecome larger, more complex, and less regular in structure. True kerogens, having very highmolecular weights, develop after tens or hundreds of meters of burial.The detailed chemistry of kerogen formation need not concern us greatly. Diagenesis results mainlyin 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 (whichis often the case in nonclastic sediments but is seldom true in shales), large amounts of sulfur maybecome incorporated into the kerogen structure. The amount of sulfur contributed by the originalorganic matter itself is very small. Carboncarbon double bonds, which are highly reactive, areconverted into saturated or cyclic structures.Kerogen formation competes with the destruction of organic matter by oxidative processes. Mostorganic oxidation in sedimentary environments is microbially mediated. Microorganisms prefer toattack 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 enzymesystems do not know how to attack them. In an oxidizing environment many of the small biogenicmolecules 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 theformation of geopolymers and, therefore, better organic preservation.Kerogens formed under reducing conditions will be composed of fragments of many kinds ofbiogenic molecules. Those kerogens formed under oxidizing conditions, in contrast, contain mainlythe most resistant types of biogenic molecules that were ignored by microorganisms duringdiagenesis.

KEROGEN COMPOSITIONBecause each kerogen molecule is unique, it is somewhat fruitless to attempt a detailed discussionof the chemical composition of kerogens. Even if such a description were possible, it would not beof great and direct significance to exploration geologists. What is within our reach, and ultimatelyof much greater practical value, is developing a general method of describing gross kerogencomposition and relating it to hydrocarbon-generative capacity. One way that we can begin is byclassifying kerogens into a few general types.About a decade ago workers at the French Petroleum Institute developed a useful scheme fordescribing 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 theorganisms from which all types of kerogens were derived. Subsequent investigations have identifiedType IV kerogen as well.

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

Transformation of organic material in sediments andsedimentary rocks.

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Type I kerogen is quite rare because it is derived principally from lacustrine algae. The best-knownexample 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 Shalekerogens and has given Type I kerogens much more publicity than their general geologicalimportance warrants. Occurrences of Type I kerogens are limited to anoxic lakes and to a fewunusual marine environments. Type I kerogens have high generative capacities for liquidhydrocarbons.Type II kerogens arise from several very different sources, including marine algae, pollen andspores, leaf waxes, and fossil resin. They also include contributions from bacterial-cell lipids. Thevarious Type II kerogens are grouped together, despite their very disparate origins, because they allhave great capacities to generate liquid hydrocarbons. Most Type II kerogens are found in marinesediments deposited under reducing conditions.Type III kerogens are composed of terrestrial organic material that is lacking in fatty or waxycomponents. Cellulose and lignin are major contributors. Type III kerogens have much lowerhydrocarbon-generative capacities than do Type II kerogens and, unless they have small inclusionsof Type II material, are normally considered to generate mainly gas.Type IV kerogens contain mainly reworked organic debris and highly oxidized material of variousorigins. They are generally considered to have essentially no hydrocarbon-source potential.Hydrogen contents of immature kerogens (expressed as atomic H/C ratios) correlate with kerogentype. In the immature state, Type I (algal) kerogens have the highest hydrogen contents becausethey 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 containextensive 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 oxidizedand therefore contain large amounts of oxygen. Type III kerogens have high oxygen contentsbecause they are formed from lignin, cellulose, phenols, and carbohydrates. Type I and Type IIkerogens, in contrast, contain far less oxygen because they were formed from oxygen-poor lipidmaterials.

Van Krevelen diagram showing maturationpathways for Types 1 to IV kerogens astraced by changes in atomic HIC and OICratios. The shaded areas approximatelyrepresent diagenesis, catagenesis, andmetagenesis, successively.

Kerogen - 20

Sulfur and nitrogen contents of kerogens are also variable and, in some cases, interrelated. Nitrogenis derived mainly from proteinaceous material, which is destroyed rapidly during diagenesis. Mosthigh-nitrogen kerogens were therefore deposited under anoxic conditions where diagenesis wasseverely limited. Because lignins and carbohydrates contain little nitrogen, most terrestriallyinfluenced 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 freshwaters are usually low in sulfate. Sulfur is only incorporated into kerogens in large quantities wheresulfate 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-generativecharacteristics has been supported by another independent scheme for classifying kerogens usingtransmitted-light microscopy. Kerogen types are defined by the morphologies of the kerogenparticles. In many cases the original cellular structure is still recognizable, proving the origin of theparticle. In others the original fabric has disappeared completely, forcing us to make assumptionsabout the source organisms. Microscopic organic analysis has reached a fairly high level ofrefinement 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. Thekerogen in a given sedimentary rock includes many individual particles that are often derived from avariety of sources. Thus few kerogens consist of a single maceral type.Maceral names were developed by coal petrologists to describe, wherever possible, the materialsfrom which a maceral was derived. A list of the most common macerals and their precursors isgiven in the table presented earlier in this chapter.It is possible to make a reasonably good correlation between kerogen type based on chemicalcharacteristics 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 organicmatter. 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 TypeII and Type III kerogens because of the presence of small amounts of resin or wax.

KEROGEN MATURATION

INTRODUCTIONVery important changes, called maturation, occur when a kerogen is subjected to high temperaturesover 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 moleculeseventually become petroleum and natural gas.By convention the term catagenesis usually refers to the stages of kerogen decomposition duringwhich oil and wet gas are produced. Metagenesis, which occurs after catagenesis, represents dry-gas generation. Despite its name, metagenesis is not equivalent to "metamorphism." Metagenesisbegins 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 notprecisely equivalent. Catagenesis and hydrocarbon generation occur concurrently, but they reallyrepresent different aspects of the same process. Catagenesis refers to transformations of kerogenmolecules, whereas hydrocarbon generation focuses on the production of hydrocarbon molecules. Inthis text we shall use the terms somewhat interchangeably, especially when we are discussing bothaspects 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. Thecomposition 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 decreasesin temperature occur. Chemical reaction-rate theory requires that the rates of reactions decrease astemperature decreases, but it also states that at any temperature above absolute zero reactions willbe occurring at some definable rate. For practical purposes, however, the rates of catagenesis aregenerally not important at temperatures below about 70° C. Furthermore, in most cases decreasesof temperature in excess of about 20°-30° C due to subsurface events or erosional removal willcause 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 alsoplays a role. Old rocks will often generate hydrocarbons at significantly lower temperatures thanyoung rocks, simply because the longer time available compensates for lower temperatures. Thiscomplex interplay between the effects of time and temperature on maturity is discussed in a laterchapter.

EFFECTS OF MATURATION ON KEROGENSKerogen undergoes important and detectable changes during catagenesis and metagenesis. Some ofthese changes can be measured quantitatively, thus allowing us to judge the extent to which kerogenmaturation has proceeded. The real reason for following kerogen catagenesis, of course, is tomonitor hydrocarbon generation. Although it is obvious that many measurable changes in kerogensare related to hydrocarbon generation, it is also true that other changes in kerogen properties havelittle or nothing to do with it, and thus are not necessarily valid indicators of hydrocarbongeneration. We shall look now at the various techniques for estimating the extent of hydrocarbongeneration from kerogen properties and see how closely each of them is related to hydrocarbongeneration.As we saw earlier, the cracking of any organic molecule requires hydrogen. The more hydrogen akerogen contains, the more hydrocarbons it can yield during cracking. Because many of the lightproduct molecules are rich in hydrogen, the residual kerogen gradually becomes more aromatic andhydrogen 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 indicatorof both kerogen catagenesis and hydrocarbon generation, provided that the hydrogen content of thekerogen was known prior to the onset of catagenesis.Nitrogen and sulfur are also lost from kerogens during catagenesis. Nitrogen loss occurs primarilyduring late catagenesis or metagenesis, after hydrogen loss is well advanced. In contrast, much ofthe sulfur is lost in the earliest stages of catagenesis, as evidenced by low maturity, high-sulfur oilsfound 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 hydrocarbon-generative capacity of a kerogen decreases during catagenesis and metagenesis. All kerogensbecome increasingly aromatic and depleted in hydrogen and oxygen during thermal maturation. Inthe 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 brownsduring baking. There is a steady color progression yellow-goldenorange-light brown-dark brown-black as a result of polymerization and aromatization reactions. These reactions are intimatelyrelated to important changes in the chemical structure of kerogen, but they are not necessarilyidentical 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 kerogencolor always heralds the onset of oil generation.As kerogen matures and becomes more aromatic, its structure becomes more ordered, because theflat aromatic sheets can stack neatly. These structural reorganizations bring about changes inphysical properties of kerogens. One property that is strongly affected, and which can be used togauge the extent of molecular reorganization, is the ability of kerogen particles to reflect incidentlight coherently. The more random a kerogen's structure, the more an incident light beam will bescattered, and the less it will be reflected.Half a century ago coal petrologists discovered that the percentage of light reflected by vitriniteparticles 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 inkerogens, the technique, called vitrinite reflectance, has been widely and successfully applied inassessing kerogen maturity.Cracking often produces free radicals, which are unpaired electrons not yet involved in chemicalhonds. Kerogens, especially highly aromatic ones, contain large numbers of unpaired electrons. Theconcentration of free radicals in a given kerogen has been found to increase with increasingmaturity. Free-radical concentrations can be measured by electron-spin resonance.Kerogens often fluoresce when irradiated. The intensity and wavelength of the fluorescente arefunctions of kerogen maturity.Some properties of kerogen change very little during catagenesis. For example, carbon-isotopiccompositions of kerogens are affected little by maturation. Except for darkening, the visualappearance of kerogen also does not change during catagenesis: kerogen types are generallyrecognizable until the particles become black and opaque, somewhat beyond the oil-generationwindow.

Plot of bitumen generation as afunction of maturity (dashed fine)compared to bitumen remaining inrock (solid line). The differencebetween the two curves representsbitumen expelled from the rock orcracked to light hydrocarbons.

HYDROCARBON GENERATIONAs kerogen catagenesis occurs, small molecules are broken off the kerogen matrix. Some of theseare hydrocarbons, while others are small heterocompounds. These small compounds are much moremobile than the kerogen molecules and are the direct precursors of oil and gas. A general name torthese molecules is bitumen.Bitumen generation occurs mainly during catagenesis; during metagenesis the chief product ismethane. If neither expulsion from the source rock nor cracking of bitumen occurred, there wouldbe a large and continuous build-up of bitumen in the rock as a result of catagenetic decompositionof kerogen. What actually occurs, however, is that some of the bitumen is expelled from the sourcerock 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 experimentaldata.It has become apparent in recent years that not all kerogens generate hydrocarbons at the samecatagenetic levels, as measured by parameters such as vitrinite reflectance. Given the significantchemical 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 otherkerogens because of the particular chemical reactions occurring in those two materials. Resiniteconsists of polymerized terpanes (ten-carbon isoprenoids) that can decompose easily by reversingthe polymerization process. Sulfur-rich kerogens decompose easily because carbon-sulfur hbondsare weaker than any bonds in sulfur-poor kerogens.Effective generation of hydrocarbons requires that the generated products be expelled from thesource-rock matrix and migrated to a trap. Timing and efficiency of expulsion depend on a numberof factors, including rock physics and organic-geochemical considerations. We shall consider thelatter briefly here.Many workers now believe that microfracturing of source rocks is very important tor hydrocarbonexpulsion. Microfracturing is related to overpressuring, which in turn is partly attributed tohydrocarbon generation itself. Rich rocks will become overpressured earlier than lean ones and thuswill also expel hydrocarbons earlier. In very lean rocks expulsion may occur so late that cracking ofthe generated bitumen is competitive with expulsion. In such cases the expelled products will bemainly gas.

SUMMARYKerogen begins to form during early diagenesis, when large geopolymers are created frombiological molecules. The chemical composition and morphology of kerogen macerals depend bothon the type of original organic matter and on diagenetic transformations. Numerous methods existfor tracing the history of a kerogen and determining its original chemical and physicalcharacteristics.Catagenesis of kerogen produces a more aromatic, hydrogen-poor, residual kerogen as well assmall molecules that are the direct precursors for petroleum and natural gas. Several methods existfor estimating the extent to which hydrocarbon generation has occurred in a given kerogen, butnone 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, wecannot always define the limits of hydrocarbon generation with great confidence.The chemical composition of a kerogen controls the timing of hydrocarbon generation and the typeof products obtained. Kerogens formed from lipid-rich organic material are likely to generate liquidhydrocarbons, whereas those kerogens that contain few lipids will generate mainly gas. Kerogensformed from resinite will generate condensates or light oils quite early. High-sulfur kerogensgenerate heavy, high-sulfur oils at low levels of maturity. Other kerogens usually follow a moretraditional model.Source rocks that generate large amounts of hydrocarbons early are likely to expel thosehydrocarbons early. Candidates for early expulsion would be very organic rich rocks and thosecontaining resinite or high-sulfur kerogens. Conversely, those rocks that generate few hydrocarbonsmay not expel them until they have been cracked to gas.

Bitumen, Petroleum, and Natural Gas -24

5 - Bitumen, Petroleum, and Natural Gas

INTRODUCTIONPetroleum obtained from reservoir rocks and bitumen extracted from fine-grained rocks have manysimilarities, but they also exhibit many important differences. There is no doubt that they arerelated; indeed, bitumen is almost universally accepted as the direct precursor for petroleum.However, many unanswered questions remain about the processes that transform bitumen intopetroleum. Major compositional changes occur in going from bitumen to petroleum, but we are notcertain whether they occur mainly within the source rock or during migration through the reservoirrock. We also do not know how much of the change involves chemical reactions, and how much isdue to physical separation of chemical compounds having very different properties. The influence ofthe 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 relatedto source-rock facies and the composition of the kerogens that generated the bitumens. Maturityalso exerts control over bitumen and petroleum composition. Reservoir transformations in somecases greatly affect oil composition and properties.Bitumen and petroleum compositions can also be used as tools in correlating samples with eachother. Such correlations can be particularly useful in establishing genetic relationships amongsamples. In order to understand bitumen and petroleum compositions and to use them forexploration, however, we must separate the characteristics related to kerogen composition fromthose related to the transformation of bitumen to petroleum and from those related to changesoccurring in reservoirs. This chapter will compare and contrast bitumen and petroleumcompositions and examine the factors responsible for the observed differences.

COMPOUNDS PRESENT IN BITUMEN AND PETROLEUM

GENERAL CLASSES OF COMPOUNDSBoth bitumen and petroleum contain a very large number of different chemical compounds. Some ofthese are present in relatively large quantities, while others are only trace contributors. In order toinvestigate the individual compounds present, we first separate a crude oil or a bitumen into severalfractions having distinct properties.Each of the fractions contains certain types of chemical compounds. One fraction consists mainly ofsaturated hydrocarbons; n-alkanes, branched hydrocarbons (including isoprenoids), and cyclics.Saturated hydrocarbons are the most thoroughly studied of the components of petroleum andbitumen 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 thesecompounds are lost from bitumens during evaporation of the solvent used in extracting the bitumenfrom the rock. Heavier aromatic and naphthenoaromatic hydrocarbons, particularly those derivedfrom 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-sizedmolecules with one or more heteroatoms. Few of these heterocompounds have been studiedcarefully.The final fraction contains very large, highly aromatic asphaltene molecules that are often rich inheteroatoms. Asphaltenes tend to aggregate into stacks because of their planarity, and formcomplexes 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 thelaboratory or refinery by adding a light hydrocarbon, such as pentane or propane. Because of theirmolecular complexity and heterogeneity, asphaltene molecules have not been studied in detail.

SPECIFIC COMPOUNDSBiomarkers. Many of the compounds and classes of compounds that we find in crude oils andbitumens are called biomarkers, an abbreviation for biological markers. These compounds, whichare derived from biogenic precursor molecules, are essentially molecular fossils. The most usefulbiomarkers 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 specificprecursor organisms or molecules can be identified, whereas in other instances we may be able tolimit the possible precursors to only a few species. In most cases, however, although we know forcertain that the biomarker molecule is biogenic, we are unable to use it as an "index fossil" forspecific organisms.Other compounds. Many other types of organic compounds in crude oils and bitumens are notconsidered to be biomarkers because they cannot be related directly to biogenic precursors. Theyare, however, of biological origin, but their sources are simply no longer recognizable due todiagenetic and catagenetic transformations.

FACTORS AFFECTING COMPOSITION OF BITUMEN AND PETROLEUM

SOURCE AND DIAGENESISBiomarkersn-Alkanes were among the first biomarkers to be studied extensively. Their high concentration inbitumens and oils is best explained by their existence in plant and algal lipids, and by theircatagenetic 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, ormembers of the n-alkane series. For the most part n-alkanes present in terrestrial plants have oddnumbers 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 C-22, depending upon the species present. The distributions are quite sharp, and no preference foreither odd- or even-carbon homologs is evident.Many sediments, of course, receive contributions of n-alkanes from both terrestrial and marinesources. Their n-alkane distributions reflect this mix.Sediments are also known that exhibit a strong preference for n-alkanes having an even number ofcarbon atoms. These n-alkanes are believed to be formed by hydrogenation (reduction) of long-chain fatty acids and alcohols having even numbers of carbon atoms. (Among the acids andalcohols present in living organisms, even-carbon homologs predominate as strongly as do the odd-carbon homologs among the n-alkanes.) Even-carbon preferences occur principally in evaporiticand carbonate sediments, where input of terrestrial n-alkanes is minimal and diagenetic conditionsare highly reducing.Carbon Preference Index, or CPI, was developed as a measure of the strength of the odd-carbonpredominance 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-alkaneconcentrations with increasing number of carbon atoms. If the number of odd- and even-carbonmembers 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

Bitumen, Petroleum, and Natural Gas -26

deviate from 1.0 even when no preference is distinguishable by visual inspection of the distributioncurve.n-Alkane distributions are greatly modified by thermal maturity. Chain lengths gradually becomeshorter, and the original n-alkanes present in the immature sample are diluted with new n-alkanesgenerated during catagenesis. Because the newly generated n-alkanes show little or no preferencefor 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 ofmaturity as clearly because the original CPI values are already very close to 1.0. It is thereforeoften 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 diageneticconditions. For economic and environmental reasons, oils having more than about 0.5% sulfur aredesignated as high-sulfur. Many high-sulfur oils contain 1% sulfur or less, but in some areas sulfurcontents can reach 7% (Monterey oils from the onshore Santa Maria area, southern California, forexample). A few oils contain more than 10%.These high-sulfur bitumens and crude oils are derived from high-sulfur kerogens. As we sawearlier, sulfur is incorporated into kerogens formed in nonclastic sediments that accumulate whereanaerobic sulfate reduction is important. Most oils and bitumens derived from lacustrine orordinary clastic marine source rocks will be low in sulfur content, whereas those from euxinic oranoxic marine source rocks will be high-sulfur.Sulfur occurs predominantly in the heavy fractions of oils and bitumens, particularly in theasphaltenes. High-sulfur oils therefore have elevated asphaltene contents.

RESERVOIR TRANSFORMATIONSIntroduction. 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 areservoir is petroleum). Thermal processes occurring in reservoirs include cracking anddeasphalting. Nonthermal processes are water washing and biodegradation. Of these, cracking andbiodegradation are by far the most important.Cracking and Deasphalting. Cracking, which breaks large molecules down into smaller ones, canconvert a heavy, heteroatom-rich off into a lighter, sweeter one. Waxy oils become less waxy. APIgravities increase, and pour points and viscosities decrease. When cracking is extreme, the productsbecome 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 thecatalytic potential of the reservoir rock. It is therefore impossible to state that cracking alwaysoccurs at a certain depth or reservoir temperature. Most oils, however, will be reasonably stable atreservoir temperatures below about 90° C, regardless of the length of time they spend there. On theother hand, a reservoir above 120° C will contain normal oil only if the oil is a recent arrival.Although the role of catalysis in hydrocarbon cracking in reservoirs has not been proven, manyworkers suspect that clay minerals are important facilitators of hydrocarbon breakdown. Catalyticeffectiveness varies greatly from one clay mineral to another, however, and our partialunderstanding 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 theoil becomes lighter. Precipitation of asphaltenes in the reservoir will lower sulfur content andincrease API gravity appreciably.Biodegradation and water washing. Water washing involves selective dissolution of the mostsoluble components of crude oils in waters that come in contact with the oils. The smallesthydrocarbon molecules and the light aromatics, such as benzene, are the most soluble. The effectsof 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 thelow solubilities of all hydrocarbons in water. Finally, water washing and biodegradation often occurtogether, with the more dramatic effects of biodegradation obscuring those of water washing.Biodegradation is a transformation process of major importance. Under certain conditions somespecies of bacteria are able to destroy some of the compounds present in crude oil, using them as asource of energy. The bacteria responsible for biodegradation are probably a mixture of aerobic andanaerobic strains. Only aerobic bacteria are believed to actually attack hydrocarbons, but anaerobesmay consume some of the partially oxidized byproducts of initial aerobic attack.Because biodegradation changes the physical properties of oils, it can have serious negativefinancial implications. Heavily biodegraded oils are often impossible to produce (Athabasca TarSands of Alberta, Canada, and the Orinoco heavy oils of Venezuela, for example). If production isphysically possible, it may be expensive or uneconomic. It is therefore important to understandwhere and why biodegradation occurs, and what its effects are on oil composition.Biodegradation may actually start during oil migration (provided required temperature and oxygenconditions are met), because oil-water interactions are maximized then. Most biodegradationprobably occurs within reservoirs, however, since the length of time an oil spends in a reservoir isusually much longer than its transit time during migration.Biodegradation can vary in intensity from very light to extremely heavy. Because the chemical andphysical 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 insome areas they are epidemic.Bacteria that consume petroleum hydrocarbons have strong preferences. Hydrocarbons are not theirvery favorite foods, and they eat them only because there is nothing else available. The preferredhydrocarbons are n-alkanes, presumably because their straight-chain configurations allow thebacterial enzymes to work on them most efficiently. Also attractive to the "bugs" are long, alkylside-chains attached to cyclic structures.After the n-alkanes and alkyl groups are consumed, the bacteria begin to destroy compounds havingonly a single methyl branch or those having widely spaced branches. Then they move on to more-highly 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 thedegree 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 oilthe sulfur content may increase by a factor of two or three. Sulfur is undoubtedly concentrated inthe oil by selective removal of hydrocarbons, and may also be added by bacterially mediated sulfatereduction.

COMPARISON OF BITUMEN AND PETROLEUMAlthough bitumens and crude oils contain the same compounds, the relative amounts are quitedifferent. In the process of converting bitumen to petroleum, either the NSO compounds are lost inlarge quantities, or they are converted to hydrocarbons. In actuality, both processes probably occur,although selective loss of nonhydrocarbons during expulsion is probably most effective inconcentrating the hydrocarbons.Bitumen composition depends strongly on the lithology of the host rock. Carbonates containbitumens that are much richer in heterocompounds than are shales, and their hydrocarbon fractionsare more aromatic. These differences are the result of the higher sulfur contents of kerogens incarbonates. Oils derived from carbonate sources are also richer in heterocompounds than oilssourced from shales.

Bitumen, Petroleum, and Natural Gas -28

NATURAL GASNatural gas contains many different compounds, although most of them are present only in tracequantities. 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 byoxidation of oil or gas or by decomposition of carbonates. The origin of the C02 can be determinedeasily by carbon-isotope measurements: the very different isotopic compositions of organic-carbonspecies and carbonates are carried over into any C02 derived from these materials. Nitrogen isthought to be an indicator of high levels of maturity formed primarily by metagenetictransformation of organic nitrogen and ammonia bound to clay minerals.Hydrogen sulfide is usually derived from high-sulfur kerogens or oils. These in turn are formedmost readily in carbonates. Thus sour gas is most common in carbonate reservoirs or in placeswhere the source rock was a carbonate. H2S could also be formed by the reaction of hydrocarbonswith sulfate in reservoirs, especially carbonates containing anhydrite.Biogenic gas, most of which occurs at shallow depths, but which can apparently form (or at leastpersist) at depths of a few thousand meters, is very dry, containing only trace amounts ofhydrocarbons heavier than methane. In contrast, the first gas produced during catagenesis is quitewet. With increasing maturity, gas again becomes progressively drier as a result of cracking of theheavier hydrocarbons to methane.

SUMMARYBitumens and crude oils contain the same classes of compounds, but their relative concentrations arequite different. These differences are in some cases related to differences in maturity; in otherexamples they are probably a result of preferential expulsion of hydrocarbons from source rocks.Individual compounds occur in quite variable proportions in bitumens. Source, diagenesis, andmaturity all exert control over these distributions. When source and diagenetic influences have beenremoved, the porphyrins, steranes, triterpanes, and n-alkanes in mature bitumens are found to bevery similar to those in crude oils and quite different from those in immature bitumens.Oil compositions can also be strongly affected by reservoir transformations, includingbiodegradation, water washing, cracking, and deasphalting. Many of the factors that influence thecomposition of oils and bitumens are well understood and predictable, and can be used to obtaininformation about paleoecology, thermal history, and reservoir conditions.Gas composition is governed first of all by whether the gas is of biogenic or thermal origin. Biogenicgas is always dry, whereas thermal gas may be wet or dry. Carbon-isotope ratios are good indicatorsof the source of gas; biogenic gas is much lighter isotopically than thermal gases. Other importantcomponents, such as CO2, N2, and H2S, are indicative of high temperatures or sulfur-rich sourcematerial.

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6 - Migration

DEFINITIONSMigration is the movement of oil and gas within the subsurface. Primary migration is the firstphase of the migration process; it involves expulsion of hydrocarbons from their fine-grained, low-permeability source rock into a carrier bed having much greater permeability. Secondary migrationis the movement of oil and gas within this carrier bed. Accumulation is the concentration ofmigrated hydrocarbons in a relatively immobile configuration, where they can be preserved overlong 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 ofevents that we call migration, we must look at each of these steps separately. This chapter wi11 notgo into the physics and chemistry of migration in detail, but will describe the most widely heldviews on the dominant mechanisms of primary and secondary migration and accumulation.

PRIMARY MIGRATION

MECHANISMSMany theories about primary migration (expulsion) have been popular at various times, but thosethat have been discounted will not be discussed here. Today there are only three mechanisms ofprimary 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 carefullystudied 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 hydrocarbonsbleed 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 bydefinition a dispersive force, whereas accumulation of hydrocarbons requires concentration.Diffusion would therefore have to be coupled with a powerful concentrating force to yieldaccumulations of appreciable size. During intense hydrocarbon generation, any contribution bydiffusion will be overwhelmed by that from other expulsion mechanisms.By far the most popular mechanism invoked today to explain primary migration is expulsion ofhydrocarbons in a hydrophobic (oily) phase. There appear to be three distinct ways in which oil-phase expulsion can occur. One occurs most commonly as a result of microfracturing induced byoverpressuring during hydrocarbon generation. When the internal pressures exceed the strength ofthe rock, microfracturing occurs, particularly along lines of weakness such as bedding planes.Laminated source rocks may therefore expel hydrocarbons with greater efficiency than massiverocks. Once the internal pressure has returned to normal, the microfractures heal. The hydrocarbonswithin the pores then become isolated again because of the impermeability of the waterwet sourcerocks 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 thestrength 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 ofbitumen had been generated in the source rock. Although the exact threshold value must varyconsiderably as a function of rock lithology and other factors, Momper's value has been widelyaccepted as a reasonable average.

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Once the threshold has been exceeded, most of the hydrocarbons are expelled, but a largeproportion of NSO compounds and heavier hydrocarbons are left behind. Thus inefficiency ofexpulsion is responsible for much of the difference in composition of bitumen and petroleum thatwe noted earlier. Primary migration is unquestionably the most difficult part of the entire migrationprocess. Therefore the threshold must represent not only a hurdle to be cleared by the bitumenbefore 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 microfracture-induced 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 NSOcompounds, we can estimate that once the expulsion threshold is reached the expulsion efficiencyfor bitumen is about 50%. Of course, this approach is rather approximate, but it does give someidea of the efficiency of expulsion.A second way in which oil-phase expulsion can occur is from very organic-rich rocks prior to theonset of strong hydrocarbon generation. This expulsion process probably releases internal pressuresin the rock, but the mechanism by which overpressuring is achieved is not understood. The organicmatter expelled consists mainly of lipids that were present in the sediment during deposition anddiagenesis. Therefore, this early expulsion mechanism seems to be limited to rocks having very highoriginal contents of lipids.Finally, oil-phase expulsion can take place when bitumen forms a continuous network that replaceswater as the wetting agent in the source rock. Expulsion of hydrocarbons is facilitated becausewater-mineral and water-water interactions no longer need be overcome. This type of expulsion isprobably 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 liquidhydrocarbons; therefore, it would be expected only in the late stages of catagenesis or in sourcerocks capable of generating mainly gas. Because neither case is of great general significance forpetroleum formation, we conclude that solution in gas is a minor mechanism for oil expulsion.

DISTANCE AND DIRECTIONThe distances traversed by hydrocarbons during primary migration are short. Primary migration isdifficult and slow, because petroleum is being forced through rocks having low matrixpermeabilities. As soon as easier paths become available, the migrating fluids will take them. Thusprimary 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 hydrocarbonssourced in the shales. Fracture and joint systems, particularly in brittle carbonate and opal-chertsource rocks, also make excellent secondary-migration pathways. Massive, unfractured source-rockunits are relatively rare; where they do exist, primary migration may be of poor efficiency. In mostcases 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 sourcerock. 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 lyingbetween two sands will expel hydrocarbons into both carrier beds.

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SECONDARY MIGRATION

MECHANISMOnce hydrocarbons are expelled from the source rock in a separate hydrocarbon phase into asecondary-migration conduit, subsequent movement of the hydrocarbons will be driven bybuoyancy. Hydrocarbons are almost all less dense than formation waters, and therefore are morebuoyant. Hydrocarbons are thus capable of displacing water downward and moving upwardthemselves. The magnitude of the buoyant force is proportional both to the density differencebetween water and hydrocarbon phase and to the height of the oil stringer. Coalescence of globulesof hydrocarbons after expulsion from the source rock therefore increases their ability to moveupward through water-wet rocks.

Retardatin of buoyant movement as anoil globule (X) is deformed to fit in to anarrow pore throat (Y). The upwardbuoyant force is partly or completelyopposed by the capillary-entry pressure,the force required to deform the oilglobule enough to enter the pore throat.If the capillary-entry pressure exceedsthe buoyant force, secondary migrationwill cease until either the capillary-entrypressure is reduced or the buoyant forceis increased.

Opposing the buoyancy is capillary-entry pressure, which is resistance to entry of the hydrocarbonglobule or stringer into pore throats. Whenever a pore throat narrower than the globule isencountered, the globule must deform to squeeze into the pore. The smaller the pore throat, the moredeformation is required. If the upward force of buoyancy is large enough, the globule will squeezeinto the pore throat and continue moving upward. If, however, the pore throat is very tiny or if thebuoyant force is small, the globule cannot enter, and becomes stuck until either the buoyant force orthe capillary entry pressure changes. When hydrocarbons cease moving, we say that accumulationhas 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, canmodify hydrocarbon movement, but it is not essential and does not change our basic model. If wateris flowing in the subsurface in the same direction as hydrocarbons are moving by buoyancy, then therate of hydrocarbon movement should be enhanced somewhat. In contrast, if bulk water movementopposes 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 DIRECTIONSecondary migration occurs preferentially in the direction that offers the greatest buoyantadvantage. Thus movement within a confined migration conduit will be updip perpendicular tostructural 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 angleto 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 thesand even as they migrate laterally updip. This fact has important implications for tracingmigration 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 directionwill be exerted by the upper part of the bed (assuming that no laterally continuous shale breaksdivide the carrier bed into two or more separate systems).Vertical migration can also occur across formations. Stacked sands in a paleodelta, for example, canoffer possible pathways (although sometimes rather tortuous ones) for vertical migration.Unconformities also can juxtapose migration conduits, thus providing a potentially very effectivesystem for combined vertical and lateral migration. Faults may play an important role in verticalmigration, 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 highpermeability.The question of long-distance migration has been much discussed and disputed. There is no a priorireason why secondary migration cannot be a very-long-distance phenomenon. Indeed, the largesthydrocarbon deposits known, including the Athabasca Tar Sands of western Canada, the heavy oilsin the Orinoco Belt of Venezuela, and the Saudi Arabian crude oils, all must have migrated longdistances; otherwise it is impossible to account for the incredible volumes of hydrocarbons in placetoday.The problem in discussing long-distance migration is that such cases are rare. However, they arerare for very good geological reasons: they occur in extremely stable tectonic settings where majorbut gentle downwarping has deposited and matured huge volumes of source rocks, and has providedas carrier beds continuous blankets of sand juxtaposed with these source rocks. The absence of bothtectonic and stratigraphic barriers permits long-distance migration.Most basins, however, are broken up tectonically and have poor lateral continuity of carrier beds, asa result of both tectonic disruption and facies changes related to tectonic events. Lateral migration istherefore often stymied, leading to smaller fault-bounded accumulations and vertical migration.Drainage area is one of the most important factors influencing the size of hydrocarbonaccumulations. Long-distance migration implies, by definition, large drainage areas and chances forvery large accumulations. Lack of long-distance migration opportunities implies that supergiant andgiant 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 exceptionalcircumstances. Much more common, however, are basins in which lateral migration distances do notexceed a few tens of kilometers. Vertical migration distances can also be considerable, although itshould 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" migrationrather painlessly. Vertical migration across stratigraphic boundaries is more difficult. Nevertheless,distances of several thousand feet are not unheard of.

ACCUMULATION

INTRODUCTIONIn the old days, when migration was thought to occur mainly in water solution, the process ofhydrocarbon accumulation was somewhat mystical. Hydrocarbons had to remain in solution untilthey reached the trap, at which time they suddenly became immiscible with the water and formed aseparate hydrocarbon phase. Various mechanisms for exsolution were proposed to explain how allthis was supposed to happen.Today we believe that hydrocarbons migrate as a separate phase. This model greatly simplifies theproblem of accumulation, because now accumulation can occur where the buoyancy-drivenmovement 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-entrypressures 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 extensionaltectonism endemic to rift basins. Lateral migration is of necessity short distance, and vertical migration becomesimportant. Accumulations are small because drainage areas are small.

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

KINETIC TRAPSKinetic traps represent a fundamentally new concept in trapping mechanisms for hydrocarbons. Thesimple principle behind a kinetic trap is that hydrocarbons are supplied to the trap faster than theycan leak away. Seals in the traditional sense of the word may not exist. This model requires, ofcourse, that strong hydrocarbon generation and migration is going on today. The Elmworth Field inthe Alberta Deep Basin of Canada is the prototype for kinetic gas accumulations. Gas generated inthe late stages of kerogen catagenesis in the Alberta Deep Basin is trapped in a sandstone bedhaving lower permeability than the overlying sand. The low permeability sand thus creates abottleneck to gas migration. Because gas generation is very rapid, the low-permeability sandsbecome filled with gas. Gas production is actually from the low-permeability sand rather than fromthe high-permeability sand updip and downdip. No traditional seal exists. Because the highpermeability sand updip allows gas to migrate rapidly through, it remains water wet. Thus theElmworth Field exhibits a water-over-gas contact.High rates of hydrocarbon generation can actually create traps by causing tensile failure of sourcerocks that have become overpressured as a result of hydrocarbon generation. Fracturing associatedwith high races of oil generation in the Green River Shale has created a supergiant accumulation atAltamont.The much smaller Antelope Field produces from the Mississippian Bakken Formation, a fracturedshale that is both source and reservoir. Much of the hydrocarbon storage at Antelope is apparentlyin 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 kineticaccumulations in a slightly different sense. Cap-rocks in those fields are often poor, and would beincapable of sealing accumulations for long geologic periods. Because intense oil generation isgoing on now, however, large accumulations have formed despite high rates of leakage.

TAR-MAT TRAPSTar mats produced by biodegradation can create excellent seals. In cases where no other structuralor stratigraphic trapping mechanism exists, tar mats may provide the only possible means forretaining any hydrocarbons. Accumulations beneath tar-mat seals are generally biodegradedthemselves, because the same conditions that created the tar mat persist in the subsurface. Despitethe rarity of tar-mat seals, and the poor producibilitv of the hydrocarbons they trap, tar-mat trapsare worth discussing because they include the largest hydrocarbon accumulations known: those ofthe Athabasca Tar Sands and the Orinoco heavy-oil belt.

GAS HYDRATESFormation of crystalline hydrates of natural gas provides an extremely efficient trappingmechanism for natural gas, especially methane. Gas hydrates form and are stable under pressure-temperature regimes that occur at depths of a few hundred meters below the sea floor in deepwater, and in zones of permafrost. The base of the gas hydrate zone forms a pronounced seismicreflector that often simulates bottom contours and cuts across bedding planes. These gas hydratesconsist of a rigid lattice of water molecules that form a cage within which a single molecule of gasis trapped. Methane is by far the most commonly trapped gas molecule, but hydrates large enoughto accommodate butane molecules are known.One important feature of methane hydrates is that they are much more efficient at storing methanethan is liquid pore water. Because hydrate zones are often hundreds of meters thick, the quantitiesof gas in such accumulations are huge.A second characteristic is that gas hydrates form effective seals against vertical hydrocarbonmigration. Formation of hydrates thus provides an important trapping mechanism, because much ofthe methane trapped is biogenic and was formed in young, unconsolidated sediments that would haveno other means of retaining the methane.At the present time the vast potential of gas-hydrate accumulations is just beginning to berecognized. 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 COMPOSITIONIt has already been suggested that most of the compositional changes seen between bitumens andnormal 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 thusare not expelled as efficiently with the oil phase. Once expulsion has occurred, there may be achromatographic effect during secondary migration. The polar molecules once again interact moststrongly with interstitial water and mineral surfaces, and thus get left behind as the oil globule orstringer moves upward.Phase changes occur as a result of decreases in pressure and temperature during migration. Whenthe original hydrocarbon phase contains large amounts of light components, these changes intemperature and pressure can cause separation of the original phase into a liquid phase and a gasphase. The gas phase will, of course, contain mainly light components, but it may also include someheavier 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. Whenseparation of a single hydrocarbon phase into two phases occurs, both new phases will havecompositions that differ drastically from the original phase. Many light oils (often calledcondensates) probably have such an origin

Proposed separation of petroleum components during secondarymigration as a result of chromatographic effects. Polar compoundsinteract more strongly with water and rock minerals and thus movemore slowly than hydrocarbons.

SIGNIFICANCE FOR EXPLORATIONExplorationists who are reading about migration will surely ask, "What does this mean forexploration?" From their perspective the important aspects of primary migration are the nature ofthe hydrocarbons expelled (oil or gas), the efficiency of expulsion, and the timing of expulsion. Wehave already stated that oil is expelled primarily as a liquid phase; gas is presumably expelled as agas phase. Efficiency of expulsion of liquids has already been estimated to be in the neighbourhoodof 50% after the expulsion threshold has been reached. Efficiency of expulsion for hydrocarbons isapparently much higher than for NSO compounds, leading to an enrichment of hydrocarbons in theexpelled liquid.Timing of expulsion must be dealt with in a different way. We already know two important factsabout timing from our previous discussion: expulsion based on microfracturing cannot occur beforegeneration, and expulsion occurs concurrently with generation to relieve generation-inducedoverpressuring. Thus if we can determine the timing of generation, we will also have determined thetiming of expulsion.In using our understanding of secondary migration for exploration, we want to determine the mainpathways and conduite through which migration occurs, the barriers that modify die direction ofmigration and eventually stop it, and the vertical and horizontal distances involved. Proximity toeffective source rocks and their permeabilities to hydrocarbons determine conduits. Pathways, as wehave seen, are determined by structural contours on the top of the carrier beds. Barriers can becreated by folding, by faulting, by decreases in permeability as a result of facies changes, or by thepresence of tars. Vertical-migration distances can be considerable, depending upon stacking ofreservoirs, vertical faulting, and the possibilities of combined vertical and lateral migration. Lateral-migration distances are strongly influenced by tectonic and depositional histories of basins.Tectonically stable basins have the best potential for long-distance migration and supergiantaccumulations. Unstable basins seldom have depositional or tectonic continuities necessary for long-distance lateral migration to occur.In summary, as explorationists we have very pragmatic interests in migration. We need to knowwhen hydrocarbons moved, in what direction they moved, and how far they moved.

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7 - Petroleum TrapsWe have seen petroleum generated in and expelled from the source rock formation into an overlying orunderlying reservoir. If it can, it will escape to surface as a seepage, where it is lost. If then we are tofind any of it still preserved, not only must the reservoir be overlain by an impervious layer forming acap rock or seal (shales or evaporites are likely to be the most effective), but there must also be somesort of blockage to prevent further migration. This may be caused either by the reservoir itself dying outor by an interruption of its upwards continuity to the surface. Such a configuration of the reservoir isknown 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 consistlargely of finding a trap, drilling a well into it, and hoping for the best. Nowadays we can do better, andfurthermore we can map out the extent and shape of the trap with a good deal of precision-thanksmostly to modern seismic techniques.

THE REPRESENTATION OF TRAPSTraps are commonly depicted in two ways. First, they can be mapped by means of contours drawn onthe top of the reservoir formation. A structure contour map resembles an ordinary topographic contourmap, except that the contours are in depth below sealevel, so that the highest points on the map have thelowest values. Faults will be marked by jumps of the contours, as the beds on one side are droppeddown relative to the other.To complement the structure contour map, one or more cross-sections may be drawn. To give a truerepresentation, they should properly be drawn with the same scale for both the vertical and thehorizontal, 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 reservoirformations 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 sea-level. (a) A simple hypothetical anticline. (b) A representation of the Piper field in the North Sea: the heavylines are faults cutting the top of the reservoir and causing the contours to jump; the ticks are on thedownthrown 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 anexample. The highest point of the reservoir, up towards the ground surface, is known as the crest of thetrap. 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 thecrest is referred to as the closure, and the same term is used loosely to refer to the area of the trapabove 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 canrecognize a generally horizontal oil-water contact. Similarly gas, being lighter still, will occur as a gascap 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 sameor overlapping areas, perhaps if more than one reservoir is present, they are embraced by the familiarterms oilfield or gasfield.Just a couple more terms. The vertical height of the oil (or gas) between the crest of the trap and thewater contact is the oil- (or gas-) column. When referring to a single well, the informal term pay isoften 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 tobe discounted and the bits that remain as useful reservoir in a well section may be lumped together asthe net reservoir with a net pay.

Some terms used to define a trap, using across-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 normallyclassified 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 intheir 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 entirelydue to either.4. Hydrodynamic traps, which are rare and are mentioned mainly for completeness. The trap is due towater flowing through the reservoir and holding the oil in places where it would not otherwise betrapped.

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

Petroleum Traps - 38

anticlines with different shapes and geometries that can affect both their prospectivity and the positionsof optimum drilling locations: we have to try to understand them. Traps can also be formed againstfaults 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 importanttypes 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, theanticline is asymmetrical, with one flank steeper than the other, then the position of the crest will shiftwith increasing depth; therefore in order to drill into a reservoir near its highest point (where we wouldexpect the oil to be), we have to know its depth to know where best to locate the well. Seismic mayhelp, but we commonly have to undertake some form of geometrical construction to interpret what ishappening at depth. This leads us into the next problem.Compressive structures have a range of shapes between the purely concentric or parallel anticline andthe similar fold, depending on the nature and strength of the rock layers being folded. Let us see whatthe implications are for exploration.

Cross-sections of trap-forming anticlines. (a) The dips are the same onboth 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 atsurface.(2-22)

In the concentric fold the tops and bottoms of all the layers remainstrictly parallel to each other, so that the beds maintain a constantthickness throughout. These conditions mean that the anticlinebecomes smaller and tighter at deeper levels until we reach acommon `centre of curvature'. Below this point we have just toomuch 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, wecan thus expect to find only smaller and smaller accumulations of petroleum down to the centre ofcurvature, beyond which there may be no trap left to explore as the consequence of decoupling oflayers. 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 onlyhappen if there is an apparent thickening of some beds over the crest of the fold. In this case, we canfind the trap present at all levels down to the basement, and we may be able to continue explorationdown to depths where we have to stop for other reasons. This is a very different kettle of fish from theconcentric anticline. In practice, many structures have forms in-between the two extremes, but anunderstanding 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 thedrape or drape-compaction structure. Imagine an old-fashioned stone hot-water bottle in a bed with ablanket over it: we can still see the form of the hot-water bottle, and the blanket bulges upwards with ananticlinal shape. Cover it with a few more blankets and a duvet or two, and we may no longer be able tosee where the bottle is.

Petroleum Traps - 39

A drape-compaction anticline, the beds being draped over anupfaulted block (horst) of basement rocks. Note that theanticline 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 upfaultedblock or horst, then they will blanket the hill as an anticline; higher beds will gradually mute andsuppress the structure until it is no longer present at shallow levels. A second effect comes into playhere: because there is a greater thickness of beds off the structure than over the top, those near thebottom of the sequence are going to be squeezed and compacted more on the flanks than on top of thefeature as it gets buried. This compaction enhances the anticline formed by the drape; it is not alwayseasy to separate out the two effects, and hence the combined name. In case anyone should think that thisis unimportant, note that the largest oilfield in the world, Ghawar in Saudi Arabia, which contains morethan four times as much oil as the whole of the North Sea put together, is in one such trap. Another isthe Forties field in the North Sea, where the beds are draped over the eroded stumps of an old Jurassicvolcano.The effect of salt diapirism will be initially to bulge up the overlying sediments as an anticline, a saltpillow or a salt dome, and then to burst through them in the form of a salt plug or salt wall; it mayextend up to the surface of the ground or only part way if the supply of salt is limited.

Diagrammatic section through two saltplugs, showing the variety of traps thatmay be associated with them. Note alsothat salt, being plastic, can be aperfect seal to any underlyingaccumulations.(2-26)

A wide variety of traps can beassociated with salt plugs. Not onlymay an anticline be pushed up overthe 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 cutsthrough, and finally a residual bulge may be left between two nearby plugs: a turtle or turtle-backstructure. All of these possible traps may contain hydrocarbons. Extensive salt deposits and plugs withassociated traps occur in many parts of the world: the southern North Sea and northern Germany; theGulf Coast of the USA; the Canadian Arctic Islands; much of the west coast and continental shelf ofAfrica; 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 anormal fault that is curved, so that it is steep near the surface and flattens with depth. In effect thedownthrown side is being pulled away from the upthrown side which would tend to create an openfissure along the fault. Nature, however, does not like empty holes, and the beds on the downthrownside above the curving fault collapse to fill the gap, bending downwards into the hole. This creates arollover 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 itsdepth, to locate an exploration well in the right place.

Roll-over anticlines: (A) a simple roll-overinto a normal fault; (B) a roll-overcomplicated by subsidiary faulting nearthe crest. Note that, in both cases, theposition of the crest is displaced withdepth and that accumulations insuccessive reservoirs will not underlie thesame surface position.(2-27)

These roll-over structures are particularly important where the `stretching' is caused by a very thick pileof sediments at the edge of a continent gently slipping, or slumping as a sort of land-slide, downtowards the deep ocean. Much of the oil under the Niger and Mississippi Deltas is in such roll-overanticlines.

Fault traps We indicated above that a trap may be formed where a dipping reservoir is cut off up-dipby 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 ofsouthern England offers a splendid example.

Cross-section through theWytch Farm oilfield, southernEngland. The oil is in tworeservoirs, trapped againstfaults to the south; thesepredated the deposition of theUpper Cretaceous.;Tr, Triassic; L, Lower Jurassic;BS+MJ+O, Middle Jurassic;Kim+P, Upper Jurassic; W, LowerCretaceous; UK, UpperCretaceous; T, Tertiary. (2-28)

We do not propose to discuss fault traps in detail, although there are many problems in trying to locatethem 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 orreverse; and it will depend on the amount of displacement on the fault, whether or not the reservoir iscompletely 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 thefollowing figure in which the faults themselves are non-sealing, thus causing sand against sand topermit migration and sand against shale to be sealing.The sealing capacity of faults is a major difficulty confronting us. We know that sometimes, as atWytch Farm, a fault can provide a seal, but we also know that sometimes faults are pathways formigrating petroleum and non-sealing at all. Occasionally indeed, it seems that one and the same faultmay act, or have acted in the past, in both ways. All very puzzling! Although attempts have been madeto 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 ourpredictions 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 orreverse, on the direction of dip of the beds relative to the fault plane, and on the amount of displacement ofthe reservoir. It is presumed that petroleum cannot escape up the fault plane.(2-29)

STRATIGRAPHIC TRAPSPetroleum 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 largeextent reflecting the restricted environments in which the reservoir rocks were deposited. It would bepointless to list all of the possible types of stratigraphic trap that can exist, so we will mention a few toconvey 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 byunconformities; they differ somewhat in principle from the others, but are generally classified asstratigraphic traps. A dipping reservoir, cut across by erosion and later covered above the unconformityby impermeable sediments, provides the classic case: the East Texas field, for example, is the biggest inthe USA outside Alaska.Unconformity traps can also be found above the break. Consider the sea gradually encroaching over theland as sea level rises; the beach sands will spread progressively over the land surface, becomingyounger as time goes on, until perhaps the supply of sand runs out. We would be left with a sandstonereservoir 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 permeablerock; 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 inChina and North Africa.Non-unconformity traps are even more diverse. We mention just three examples. A coral reefoverwhelmed by muds, may serve as an isolated stratigraphic trap. A sand deposited in a river channelwill be confined by the banks and, if terminated updip as not infrequently happens, we have an isolatedtrapping 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 willprovide an example of a reservoir dying out laterally. A lot of oil has been found in recent years in thissort 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 tobe something new as a challenge.

An investigation into thesealing qualities of faultsaffecting roll-over anticlinesin the Niger Delta, where thereservoirs overlieoverpressured shales. Wherea reservoir is full to spill-point against a fault, andwhere an oil-water contact iscontinuous across a fault, it ispresumed that the fault isnon-sealing; elsewhere itappears to form a trap. Thedifference is believed to bedue to clay being smearedinto the fault plane, wherethere is enough of it in thesection, as the fault moved.(2-

30)

COMBINATION TRAPSA number of fields, some of them large, occur in traps formed by a combination of structural andstratigraphic circumstances; neither completely controls the trap. Again the range of possibilities isalmost 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 gastrapped in a Carboniferous to Jurassic sequence which includes more than one reservoir; these bedswere folded into a faulted east-west anticline, tilted westwards, and truncated by erosion. The oil is heldin the reservoirs by younger shales overlying the erosion surface (Fig.).

A block representation of the trap at the PrudhoeBay field in northern Alaska. The reservoir bedswere folded into an anticline, which was tilted westand eroded before deposition of the overlying bedsnow dipping east. This combination trap is partlystructural (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 toJurassic reservoirs, which were eroded and unconformably overlain by Cretaceous shales. Both thefaulting and the unconformity control the traps.We may note here one most important consideration. The oil in these fields can only have migratedthere after the traps were sealed by the higher sequences, or the oil would have been lost. This vitalfactor, 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 proposingexploration drilling. The timing of trap formation versus oil migration has not always worked outfavorably.

HYDRODYNAMIC TRAPSImagine surface water, perhaps from rain, entering a reservoir formation, or aquifer, up in the hills andpercolating downwards towards a spring. Oil has found its way into the reservoir and is battling tomigrate upwards to the surface against the flow of water. Depending on the balance of forces acting onthe oil, it may find itself caught against an unevenness of the reservoir surface where there is noconventional trap at all. This is what has been described as a hydrodynamic trap. It is totally dependenton the flow of water and is effective, of course, only for as long as the water keeps coming: dry up thesupply of water, and the oil will be free to move again. This may be one of the reasons why oilaccumulations trapped hydrodynamically are rare; a regime of water flow cannot normally be expectedto 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 numberof parts of the world. In this sort of situation, we would have to be careful where we locate and drill ouroil production wells, as we do not want to waste the money drilling wells that would miss the oilaltogether. Furthermore, cases are known where flowing water has apparently been able totally to flushoil out of an anticlinal trap. We would recognize this from residual traces of oil in a water-bearingreservoir, indicating the former presence of an oil accumulation now lost. It is therefore alwaysimportant to get a handle on the hydrodynamic regime in a reservoir for both exploration and oilfielddevelopment purposes.

A hydrodynamic trap. Oil, attempting to escape tosurface up a reservoir, is held against an unevennessof its upper surface by water flowing in the oppositedirection. There is no structural or stratigraphicclosure. Note that the oil-water contact is tilted downin the direction of water flow.(2-32)

THE RELATIVE IMPORTANCE OF TRAPSA review of 200 giant oilfields (those containing 500 million barrels or more) emphasize theimportance of structural, essentially anticlinal, traps in both number and size. The number ofstructural field of this size may partly reflect the fact that structural traps are easier to find thanthe others, but the oil reserves they contain show clearly that generally they are also bigger. Thetrouble, from our present-day point of view, is that in most parts of the world the largeranticlines have now been drilled. What our efforts are increasingly directed towards, therefore,are the more obscure and generally smaller prospects.

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

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EXERCISE PetroleumTraps 2The Wyckoff Gas Field, located in Steuben County, N.Y., produces from Onondaga Limestone and/or Oriskany Sandstone. The Onondaga forms athick 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 down-

to-the-southwest faultextends upward along thesouthwest flank of the reef.Oriskany production isfrom a small anticline onthe upthrown side of thefault.Elevations and marked logsare provided for 6 wells inthe Wyckoff Field. Use thisinformation to construct anortheastsouthweststructural cross sectionfrom the Richards well tothe Dibble well, showing theinterval from top ofOnondaga to bottom ofOriskany.

Wyckoff Reef Gas FieldWellElevation

CORNELL 2257'DIBBLE 2098'GUILD 2037'CHASE 2206'BANKS 2182'RICHARDS 2066'

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Petroleum Traps - 48

Source Rock Evaluation - 49

8 - Source-Rock Evaluation

DEFINITION OF SOURCE ROCKMuch of modern petroleum geochemistry depends upon accurate assessment of the hydrocarbon-source capabilities of sedimentary rocks. Although the term source rock is frequently usedgenerically to describe fine-grained sedimentary rocks, that usage is a bit too broad and loose. Forbetter communication. the following distinctions can be made:

Effective source rock: any sedimentary rock that has already generated and expelledhydrocarbons.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 andexpelling 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 oneplace; a potential source rock in a less-mature area; a possible source rock in a nearby unstudiedregion; and might have no source potential at all in a fourth area where important facies changeshad resulted in a drastically lower content of organic matter. For example, the PhosphoriaFormation 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 fromearliest maturity to overmaturity. When we analyze a rock sample in the laboratory, we actuallymeasure its remaining (or untapped) source capacity at the present day. This quantity, which wecan call G, is most meaningful if we can compare it to the rock's original source capacity, Go. Thedifference between Go and G represents the hydrocarbons already generated in the effective sourcerock. However, we cannot measure G directly for a sample that has already begun to generatehydrocarbons; instead it must be estimated by measuring G for a similar sample that is stillimmature. Go can only be measured directly for immature source rocks, where G and Go areidentical.

PRINCIPLES OF SOURCE-ROCK EVALUATION

QUANTITY OF ORGANIC MATERIALThe amount of organic material present in sedimentary rocks is almost always measured as thetotal-organic carbon (TOC) content. This simple, quick, and inexpensive analysis serves as the firstand most important screening technique in source-rock analysis. Analysis normally requires aboutone gram of rock, but if the rocks contain abundant organic matter, much smaller amounts can beanalyzed.The quantity actually measured in the laboratory is always G, the remaining source capacity andnot the original capacity (Go).

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

Source Rock Evaluation - 50

hydrocarbon-source capacity has already been used up)? The exploration implications of these twoscenarios are, of course, very different.A substantial number of techniques for measuring or estimating kerogen maturity have beendeveloped over the years. All the methods have strengths and weaknesses, and none can be appliedin all cases.The feeling of most workers today is that there is no single maturity indicator that tells the wholestory unerringly all the rime. All the techniques discussed are useful and probably reasonablyaccurate if the analytical work is carefully done. The key to using maturity parameters effectivelylies in evaluating the measured data carefully (and sometimes with skepticism) and, wheneverpossible, in obtaining more than one maturity parameter.The most commonly used maturity parameters today are spore color (Thermal Alteration Index, orTAI), vitrinite reflectance, and pyrolysis temperature. Less commonly used are fluorescence andconodont color (CAI). A few of these parameters will briefly be discussed.

Vitrinite reflectance (Ro). Vitrinite-reflectance techniques were developed for measuring the rankof coals, in which the vitrinite maceral is usually very common. The method is based on the factthat with increasing thermal stress, the reflectance value of vitrinite increases.Vitrinite-reflectance measurements begin by isolating the kerogen with HCl and HF, and thenembedding the kerogen particles in an epoxy plug. After the plug is polished, the microscopistshines light on an individual vitrinite particle. The fraction of the incident beam that is reflectedcoherently is measured and recorded and stored automatically on a computer. If enough vitriniteparticles can be found, between 50 and 100 measurements will be taken. At the end of the analysisa histogram of the collected data is printed, along with a statistical analysis of the data. Results arereported as Ro values, where the o indicates that the measurements were made with the plugimmersed in oil. Reflectance values are normally plotted versus depth in a well. If a log scale isused for the reflectance, the plot is a straight line.There are many problems with vitrinite reflectance as applied to kerogens. In many rocks vitriniteis rare or absent. Because what is present is often reworked, its maturity is not related to that ofthe rock in which it is found. Reworked vitrinite is, in fact, far more common in shales than incoals, leading to frequent difficulties in establishing which vitrinite population is indigenous. Theideal histogram of reflectance values is therefore rather rare; more common are histogramsshowing few vitrinite particles or multiple modes as a result of first-cycle vitrinite contaminatedwith reworked vitrinite or caving of less-mature material from up-hole. Such histograms are quiteoften difficult or impossible to interpret, unless surrounding samples help us determine theindigenous vitrinite population.Other macerals or solidified bitumens can often be misidentified as vitrinite. Because each maceraltype 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 estimatingkerogen maturity. In many areas it is easy to use and valuable. In other rocks, however, paucity offirst-cycle vitrinite renders vitrinite-reflectance measurements essentially worthless. In all cases it isworthwhile 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 formicroscopic kerogen-type analysis. The darkening of kerogen particles with increasing thermalmaturity can be used as an indicator of maturity. In order to minimize differences in color causedby changes in the type or thickness of the kerogen particles, TAI measurements are carried out onbisaccate 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 colordeterminations they are now making with those they and their colleagues made in the past. Acareful worker can reproduce earlier work with excellent precision, thus defusing to a large degreethe criticism that TAI is too subjective to be valid.Although TAI determinations are subjective, use of careful standards and the same type ofpalynomorph in each analysis greatly aid reproducibility. TAI measurements are therefore oftenquite accurate and correlate very well with results from other techniques. The chief problems arisewith inexperienced workers, lack of proper standardization, or most commonly, the absence ofspores and pollen in the samples. When palynomorphs are absent, TAI values must be estimatedfrom amorphous debris, which can vary greatly in its chemical and physical properties. TAIvalues estimated from amorphous material are always suspect and should be corroborated by otheranalyses.

Conodont Alteration Index (CAI). Conodonts are isolated, most commonly from fossiliferouscarbonates, by removing the mineral matrix with acetic or formic acid. Colors of the specimensthus obtained are determined under a binocular microscope and compared with standards. Thetechnique is simple and quick and can be done even by inexperienced workers.Although conodonts are composed of carbonate apatite, changes in conodont color are apparentlydue to carbonization of inclusions of small amounts of organic matter during catagenesis andmetagenesis. One advantage of CAI over other maturity parameters is that because conodontsexisted as early as the Cambrian, they offer a means of measuring maturity in rocks that do notcontain pollen grains or vitrinite. Furthermore, conodonts are plentiful in carbonate rocks, wherepollen and vitrinite are often absent. Thirdly, the CAI scale is most sensitive at levels of maturitymuch higher than can be measured by TAI, and thus helps expand the range over which maturitiescan be measured. Finally, CAI is inexpensive and easy to measure and, with the help of colorcharts can be carried out by inexperienced personnel.One disadvantage of CAI measurements is that CAI values can be dramatically increased in thepresence of hot brines, leading to an inaccurate assessment of kerogen maturity. Otherdisadvantages overlap with some of the advantages. Conodonts do not occur in rocks younger thanthe Triassic, and thus are of no value in many areas. Conodonts are not very sensitive indicators ofmaturity within the oil generation window, where most of the interest is. Finally, because theorganic metamorphism displayed by conodonts is not related to hydrocarbon generation ordestruction, CAI is only an indirect indicator of hydrocarbon maturity.Carbon Preference Index (CPI). The first maturity indicator applied to sediments was theCarbon 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 useof CPI as an indicator of maturity. Later it was realized that the decrease in CPI with increasingmaturity depends upon the type of organic matter originally present as well as on maturity. Inparticular, rocks deposited in pelagic environments, in which the input of terrestrial lipids wasvery limited, have low CPI values even when immature.Furthermore, in the last decade kerogen analyses have replaced bitumen analyses as the routineprocedure in source-rock evaluation. As a result, fewer CPI determinations are made now.

CONTAMINATION AND WEATHERINGSurface Samples -The types of contamination most frequently encountered in surface samples arecaused by living organic matter or by spills of oil. Problems with living organic matter are easilyavoided by physically removing tiny plant roots and other recognizable debris. Mold or othersurface growth may also be present. Hydrocarbon contamination is rare except in the immediatevicinity 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 cavingand adulteration by drilling-fluid additives. Caving is not a problem for conventional or sidewallcores, of course, but it can be devastating in cuttings samples. Careful picking of lithologies andcomparison 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 aparticular problem for coals, because of their friability; it can lead to an overly optimisticassessment 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 lignitefrom lignosulfonates. Fortunately, palynological analysis can usually detect the presence oflignosulfonates because of the unique pollen assemblages present in the lignite. In such cases TOCvalues will be raised and reflectance histograms will show a large population near 0.5%. Walnuthulls and other organic debris are also easy to detect microscopically, and can be removed prior tobeginning the analytical sequence.In contrast to solid additives, which affect only the kerogen portion of the sample, diesel fuelaffects both kerogen and bitumen. It is capable of impregnating sidewall and conventional cores aswell as cuttings. TOC values will be raised and vitrinite-reflectance values lowered by the presenceof adsorbed diesel.

ESTIMATION OF ORIGINAL SOURCE CAPACITYOf the three major methods of determining kerogen type, only microscopic analysis is relativelyunaffected by maturity. As long as kerogen particles are not completely black, they can usually beidentified 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-pronedisappears toward the end of the oil-generation window.Pyrolysis yields are, of course, strongly affected by maturity. The most common method for takingmaturity effects into account in evaluating pyrolysis data is to use a modified van Krevelendiagram to backcalculate the original hydrogen index. This method works fairly well if the kerogenis still within the oil-generation window. It breaks down at high maturity levels, however, becauseall kerogens have low pyrolysis yields. Without additional information, therefore, it is impossibleto 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 itsoriginal 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 tocalculate Go.

INTERPRETATION OF SOURCE-ROCK DATA

QUANTITY OF ORGANIC MATERIALAlmost all measurements of the amount of organic matter present in a rock are expressed as TOCvalues in weight percent of the dry rock. Because the density of organic matter is about one-halfthat of clays and carbonates, the actual volume percent occupied by the organic material is abouttwice the TOC percentage.Those rocks containing less than 0.5% TOC are considered to have negligible hydrocarbon-sourcepotential. The amount of hydrocarbons generated in such rocks is so small that expulsion simplycannot occur. Furthermore, the kerogen in such lean rocks is almost always highly oxidized andthus of low source potential.Rocks containing between 0.5% and 1.0% TOC are marginal. They will not function as highlyeffective source rocks, but they may expel small quantities of hydrocarbons and thus should not bediscounted 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 TOCvalues between 1% and 2% are associated with depositional environments intermediate betweenoxidizing and reducing, where preservation of lipid-rich organic matter with source potential foroil can occur. TOC values above 2% often indicate highly reducing environments with excellentsource potential.Interpretation of TOC values therefore does not simply focus on the quantity of organic matterpresent. A rock containing 3% TOC is likely to have much more than six times as much sourcecapacity as a rock containing 0.5% TOC, because the type of kerogen preserved in rich rocks isoften more oil-prone than in lean rocks. We therefore use TOC values as screens to indicate whichrocks are of no interest to us (TOC < 0.5%), which ones might be of slight interest (TOC between0.5% 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 kerogensthey contain are woody or highly oxidized. Thus high TOC values are a necessary but notsufficient criterion for good source rocks. We must still determine whether the kerogen present isin fact of good hydrocarbon-source quality.

TYPE OF ORGANIC MATTERMicroscopic kerogen-type analysis describes the proportions of the various macerals present in asample. 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 ismainly 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, thedirect evidence for such a statement is rather meager.Pyrolysis results are normally reported in two ways. Raw data (S1, S2, and S3) are expressed inmilligrams of hydrocarbon or carbon dioxide per gram of rock sample. As such these quantitiesare a measure of the total capacity of a rock to release or generate hydrocarbons or carbondioxide. 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 hydrogenindex and the oxygen index, respectively. Because variations in TOC have been removed in thenormalizing calculation, the hydrogen index serves as an indicator of kerogen type.Measured hydrogen indices must be corrected for maturity effects by using a modified vanKrevelen diagram as outlined above. Interpretation of hydrogen indices for immature kerogens isstraightforward. Hydrogen indices below about 150 mg HC/g TOC indicate the absence ofsignificant amounts of oil generative lipid materials and confirm the kerogen as mainly Type III orType IV. Hydrogen indices above 150 reflect increasing amounts of lipid-rich material, either fromterrestrial macerals (cutinite, resinite, exinite) or from marine algal material. Those between 150and 300 contain more Type III kerogen than Type II and therefore have marginal to fair potentialfor liquids. Kerogens with hydrogen indices above about 300 contain substantial amounts of TypeII 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 IIkerogens. They have excellent potential to generate liquid hydrocarbons.

MATURITYKerogen Parameters. Determination of the oil-generation window in a particular section is theobjective of most maturity analyses performed on possible source rocks. A second, less commonapplication is to decide whether oil will be stable in a given reservoir. The limits of the oilgeneration window vary considerably depending upon the type of organic matter beingtransformed. 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 isthought to be at about 1.35% Ro. The ultimate limit of oil stability is not known for certain, but inmost cases is probably not much above 1.5% Ro.Because vitrinite reflectance is the most popular method of determining maturity, most othermaturation parameters are related to Ro values. The correlations among maturity parameters havebeen fairly well established, but there are still some minor variations from one laboratory toanother.It is particularly difficult to generalize about TAI values because the numerical values of TAIscales have not been standardized among laboratories. Thus, if you are using TAI determinationsdetermined by an analytical laboratory, make sure that you have a copy of their equivalencybetween TAI and Ro.Although Tmax values are determined objectively, because they vary with kerogen type as well asmaturity, a unified scale for comparing them with Ro values has not been adopted. Somelaboratories put the onset of maturity at 435° C; others use 440°.Conodont Alteration Index (CAI) values ranging from 1 to 5 were tied loosely to vitrinitereflectance and fixed carbon content of coals. CAI can actually measure high-grademetamorphism, with CAI of 8 reached in a marble.

COALS AS SOURCE ROCKSCoals have been traditionally discounted as effective source rocks for oil accumulations because ofthe lack of geographic correlation between oil fields and coal deposits. However, thisgeneralization 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 duringthe Cenozoic. Because some Cenozoic land plants are richer in resins and waxes than Paleozoicplants, some Cenozoic coals should have better potential for generating liquid hydrocarbons.

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SUMMARYAny 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 mostcases to answer all these questions. In some areas one technique may fail completely or may beonly partially successful. Whenever possible, therefore, we should not rely on a single analyticaltechnique; 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 onecan also learn to derive important information on thermal histories, unconformities and erosionalevents, and organic facies.We should always attempt to extrapolate our measured data over as large an area as possible. Todo this intelligently we must have the ability to develop regional models of organic facies andthermal maturity.

Vitrinite Thermal Pyrolysis ConodontReflectance Alteration Tmax Alteration(%Ro) Index (TAI) (°C) Index (CAI)

0.40 2.0 420 10.50 2.3 430 10.60 2.6 440 10.80 2.8 450 1.51.00 3.0 460 21.20 3.2 465 21.35 3.4 470 21.50 3.5 480 32.00 3.8 500 43.00 4.0 500 + 44.00 4.0 500 + 5

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

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EXERCISES

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

Source-rock data for the Mauve WellType of Atomic % Alginite

Depth (m) Sample %Corg H/C TAI + Exinite

1000 Sidewall 0.6 1.07 2.0 751200 Cores 0.8 1.22 2-2.5 801500 0.5 1.05 2-2.5 801750 0.3 0.65 2-2.5 752000 1.3 0.77 2.2 802300 0.7 0.81 2.6 902700 1.6 1.33 2.5 853000 Core 2.5 1.27 2.5 753500 Cuttings 0.5 1.15 2.6 703600 1.2 0.98 2.7 503800 1.0 0.86 2.9 454000 0.7 0.75 3.0 604500 1.5 0.72 3.1 454600 1.7 0.66 3.2 404800 2.1 0.41 3.7 ?5000 2.2 0.38 3.8 ?

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 qualitymeasurements have been made, and both should be utilized and examined for possiblediscrepancies. To use the H /C data, however, one must first convert the measured, present-dayH/C ratios to the ones that the kerogens had when they were thermally immature. This can be doneeasily by plotting H/C versus TAI, as shown in Figure B (derived from Figure A), and then tracingthe 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/Cratio(at A) from the present-day H/C ratio andvitrinite 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 "TotalOil." 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 maceralanalysis 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 immaturekerogen.

Scaled Quality Data tor Mauve Well SamplesMeasured Immature Quality Factor Quality Factor

Depth (m) H/C H/C (from H/ C) (frommacerals)

1000 1.07 1.07 1.05 * 1.51200 1.22 1.22 1.50 1.61500 1.05 1.05 1.00 * 1.61750 0.65 0.65 0.17 * 1.52000 0.77 0.77 0.35 * 1.62300 0.81 0.81 0.43 * 1.82700 1.33 1.35 1.85 1.73000 1.27 1.30 1.70 1.53500 1.15 1.20 1.35 1.43600 0.98 1.05 0.90 1.03800 0.86 1.05 0.90 0.94000 0.75 0.90 0.60 * 1.24500 0.72 0.90 0.60 * 0.94600 0.66 0.90 0.60 0.84800 0.41 ? ? ?5000 0.38 ? ? ?

* 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 forseveral of the samples. The samples at 1000, 1500, 1750, 2000, 2300, 4000, and 4500 meters allshow differences in the quality factors calculated from the two types of data. In each case, the H/Cratio 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 ofthe H/C ratios be rerun, to check for analytical error, and would certainly request that the slidesmade 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 importantpoint being made here is that these discrepanties must be taken seriously by the interpreter, and not

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be overlooked or swept under the rug. It may be necessary occasionally to offer two alternativeinterpretations 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 thetwo deepest samples. These two kerogens are highly mature and quite black. In fact, no maceralanalysis was possible here, and the H/C ratios are not helpful because the maceral types cannot beascertained from such low H/C values. One can say little, therefore, about the oil-source history ofthe section below 4600 meters.

"Total Oil" and "Oil AlreadyGenerated" profiles tor the MauveWell.

"Total Oil" and "Oil Already Generated" profiles are plotted in above figure. Most of thediscrepanties among the different quality factors turn out to be unimportant, because sourcerockpotential is not good for most of the section. The only sample where the discrepancy is significantis that from 2000 meters. "Total Oil" values are generally unexciting, although the section between2000 and 3500 meters shows fairly good potential. More samples between 3000 and 3500 metersshould 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 tohave generated anything approaching a commercially attractive amount of oil. The relative organicrichness of the blackened samples below 4600 meters makes them interesting for furtherinvestigation. Finally, a more thermally mature version of the rocks lying between 2700 and 3000meters in the Mauve Well could already have generated very large quantities of oil. Futureexploratory activity could include an attempt to find such a section.

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

Thermal-maturity data for the Blue WellDepth (ft) TAI Ro Bitumen/TOC1000 2.0 - 0.051200 2.0 - 0.071500 2.0 - 0.022000 2.0 - 0.102300 2.0-2.5 - 0.082600 2.0 - 0.093000 2.3 - 0.063200 2.3 - 0.173400 2.0 - 0.253700 2.0-2.5 0.42 0.444000 2.2 0.49 0.664200 2.5 0.46 0.614800 2.5 0.55 0.215000 2.0-2.5 0.60 0.035200 2.6 0.51 0.075400 2.5 0.59 0.095700 2.5 0.63 0.116000 2.6 0.60 0.12*TAI and Ro are interconverted according to the correlation table at the end of chapter 7.

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

Source-rock data tor the Turquoise WellDepth Type of Atomic % Alginite(ft) Sample TOC Bit/TOC H/C Ro TAI + Exinite

3000 Cuttings 1.0 0.06 0.90 0.49 2-2.5 403500 Cuttings 0.8 0.06 0.85 0.52 2.5 304000 0.7 0.05 0.86 0.59 2.5 354500 0.9 0.08 1.02 0.65 2.5-3 405000 1.1 0.91 0.91 0.67 2.5-3 505500 2.3 0.66 1.25 0.88 2.5-3 806000 2.6 0.22 1.21 0.91 2.5-3 756500 4.1 0.51 1.17 1.00 2.5-3 757000 0.5 0.08 0.65 1.07 3.0 257500 0.3 0.08 0.71 1.27 3-3.5 408000 1.8 0.27 0.99 1.21 2.5-3 708500 1.7 0.18 1.03 1.26? 2.5-3.5 809000 0.2 0.01 0.60 1.41? 3.5 209500 0.4 0.03 0.51 1.33? 3-3,5 1510,000 0.3 0.02 0.48 1.51 3.5 10

TOC = Total Organic Carbon TAI = Thermal Alteration IndexBit/TOC = Bitumen/Total organic carbon Ro = Vitrinite reflectance? indicates a poor histogram

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9 - Predicting Thermal Maturity

INTRODUCTIONMeasured maturity values for possible source rocks are invaluable because they tell us much aboutthe 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 ofthe limitations we face in attempting to obtain reliable maturity measurements. In some areas thereare no well samples available; indeed, in frontier basins there may not be a single well within tensor hundreds of kilometers.Even in maturely explored basins the samples available for analysis often do not give arepresentative picture of maturity in the basin. Furthermore, maturity measurements can only tellus about present-day maturity levels. If our measurements indicate that a rock has already passedthrough the oil-generation window, we still have no clue as to when oil generation occurred, nor dowe know at what depth or temperature it occurred. These considerations are important when wewant to compare timing of generation, expulsion, and migration with timing of structuredevelopment or trap formation.In order to circumvent these difficulties, methods have been developed for calculating maturitylevels where measurements are not available.The common thread running through all these models is the assumption that oil generation dependsupon 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 ofchemical-kinetic theory.These two factors are interchangeable: a high temperature acting over a short time can have thesame effect on maturation as a low temperature acting over a longer period. Nevertheless, earlyefforts to take both time and temperature into account in studying the process of hydrocarbongeneration were only partially successful because of the mathematical difficulties inherent inallowing both time and temperature to vary independently. In 1971, however, Lopatin in the SovietUnion described a simple method by which the effects of both time and temperature could be takeninto 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 generatedand at what depth liquids will be cracked to gas. It has even been suggested that maturity modelsare 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 andhow to use Lopatin's method in exploration.

CONSTRUCTION OF THE GEOLOGICAL MODELOne of the advantages of Lopatin's method is that the required input data are very simple and easyto obtain. We need data that will enable us to construct a time stratigraphy for the location ofinterest and to specify its temperature history. Time-stratigraphic data are usually available asformation tops and ages obtained by routine biostratigraphic analysis of well cuttings. If no welldata are available, a time stratigraphy can sometimes be constructed using seismic data, especiallyif the seismic reflectors can be tied to well data. If no subsurface data are available, estimates canbe made, perhaps from thicknesses of exposed sections nearby.

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BURIAL-HISTORY CURVESImplementation of Lopatin's method begins with the construction of a burial-history curve for theoldest rock layer of interest. An example is shown in the following figure, which was constructedfrom the time stratigraphy for the Tiger well. In the Tiger well, sediment has accumulatedcontinuously 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 followingway: 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 (pointC). 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 areparallel to those of the oldest horizon. This geometry is a direct consequence of ignoringcompaction effects.Burial-history curves are based on the best information available to the geologist. In cases wherebiostratigraphic data are available and deposition has been reasonably continuous, it is easy toconstruct burial-history curves with a high level of confidence. In cases where biostratigraphic dataare lacking or where the sediments have had complex tectonic histories, a burial-history curve mayrepresent 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 HISTORYThe next step is to provide a temperature history to accompany our burial-history curve. Thesubsurface 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 thatboth 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-holetemperature of 133° C was obtained at 3800 m. Suppose further that local weather records indicatea yearly average surface temperature of 19° C. Using these present-day data and extrapolatingthem into the past, we can construct the temperature grid with equally spaced isotherms parallel tothe earth's surface.

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Where measured bottom-hole temperatures are not available, maps of regional geothermalgradients can be useful in estimating the gradient at a particular location. In many poorly exploredareas, temperature profiles will be based largely on guesswork.There are numerous other variations that can be employed in creating temperature grids. Forexample (9-7), we can change surface temperatures through time without altering the geothermalgradient. Causes for such events could include global warming and cooling or local climaticvariations resulting from continental drift or elevation changes.

In other cases the surface temperature remains constant, but the geothermal gradient varies inresponse to heating or cooling events. As an example: lowering the geothermal gradient by rapidsediment accumulation results in subsurface temperatures that are anomalously low compared tothe "normal" ones that dominated previously. More complicated temperature histories account forchanges 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 temperaturereconstructions, we are limited only by our own creativity. In most cases, however, the datanecessary for highly sophisticated temperature reconstructions are simply not available.

SPECIAL CONSIDERATIONS ABOUT BURIAL-HISTORY CURVESThe 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 depositionresumes later, the burial-history curve again begins to trend downward.Whenever erosional removal occurs, the resultant thinning of the section must be represented in theentire family of burial-history curves. The individual segments of each of the burial-history curvesin a family will remain parallel.Faulting can be dealt with by considering the hanging wall and footwall as separate units havingdistinct burial histories. If part of the section is missing as a result of faulting, burial-history curvesfor both hanging wall and footwall can be represented on a single diagram. If, however, some partof the section is repeated as a result of thrusting, two separate diagrams should be used for the sakeof clarity.The effects of thrusting on thermal maturity are not well understood. If thrusting is rapid comparedto the rate of thermal equilibration between thrust sheets, the movement of hot rocks from thebottom 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 theOverthrust Belt of Wyoming indicate that a slow-equilibration model is superior to a simple modelinvoking rapid thermal equilibration. However, more work is required before we will understandfully 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. Individualburial-history curves remain parallel, but the distance between the two lines which bracket the erosion,decreases by 1000 m.(9-12)

CALCULATION OF MATURITYOnce the burial-history curves and temperature grids have been constructed, we must paste themtogether. Intersections of the burial-history curve with each isotherm are marked with dots. Thesedots define the time and temperature intervals that we shall use in our calculations. Temperatureintervals are defined by successive isotherms spaced 10° C apart. A Time interval is the length oftime that the rock has spent in a particular temperature interval. Total maturity is calculated bysumming the incremental maturity added in each succeeding temperature interval.Now we can carry out the maturity calculations. Chemical reaction-rate theory states that the rateof a reaction occurring at 90° C (a reasonable average for oil generation) and having a pseudo-activation energy of 16,400 cal/mol will approximately double with every 10° C increase inreaction temperature. Lopatin (1971) assumed that the rate of maturation followed this doublingrule. Testing of his model and the successful application of Lopatin's method in numerouspublished 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 atemperature factor for each temperature interval. Lopatin defined each time factor simply as thelength 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. Lopatinchose the 100°-110° C interval as his base and assigned to it an index value n = 0. Index valuesincrease or decrease regularly at higher or lower temperatures intervals, respectively. Because therate 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 forthat interval gives a product called the Time-Temperature Index of maturity (TTI). This interval-TTI 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. Maturityalways 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 ovenand turn the oven on, the cake will bake slowly at first but will bake faster and faster as thetemperature rises. If we turn off the oven but leave the cake inside, baking will continue, althoughat increasingly slower rates, as the oven cools down. On the other hand, if we forget about the cakewhen the oven is hot and let it burn, we cannot "unburn" it, no matter how much or how rapidly wecool it down.The first step in calculating TTI is illustrated in the following figure, where the time factors and y-factors for each temperature interval are shown on the burial-history curve. In the adjoining tableinterval-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 thecalculation at that time.

FACTORS AFFECTING THERMAL MATURITYBecause 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 rockcould have reached a present burial depth of 3000 mis indicated in the figure (9-21). In A the rock wasburied at a constant rate for its entire 80-my history.In B burial was very slow during the first 70 Ma ofthe 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 forthe last 50 Ma. In D 40 Ma of rapid burial to a depthof 4000 m was followed by a hiatus lasting 30 Maand, finally, by 10 Ma of uplift and erosion.TTI values differ appreciably among these fourscenarios.

Predicting Thermal Maturity - 65

A) Initial proposed burial-history model for Well #1. Themodel includes an extensivenonerosional depositionalhiatus.B) Revised burial-history modelfor Well #1 based on the poorcorrelation with measuredmaturity data. The hiatus hasbeen reinterpreted as anerosional unconformity (9-23)

POTENTIAL PROBLEMS WITH MATURITY CALCULATIONSThe most obvious errors in maturity calculations will come from inaccuracies in time andtemperature data. In actuality, time data are seldom a problem. First, the dependence of maturityon time is linear, so even a rather large error in baking time will not produce a catastrophic changein 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 incases where micropaleontological dating was not or could not be carried out, might we anticipatepossible problems with time.Temperature, in contrast, is the single most important cause of uncertainty and error in maturitycalculations. 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 theoilgeneration 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 greaterthan about time. Present-day subsurface temperatures are difficult to measure accurately. Mostlogged temperatures are too low and require correction. Various methods have been developed forthis purpose, but there is no guarantee of their accuracy in any particular case.

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Even if we could measure present-day subsurface temperatures with perfect accuracy, however, westill would have to extrapolate the present somehow into the past. In many cases, where present-day temperatures are maximum paleotemperatures, even an inaccurate extrapolation into the pastmay not cause significant problems. In other cases, however, particularly where Paleozoic rocksare involved, an accurate interpretation of the ancient geothermal history may be critical. In suchcases we should be very careful about using predicted maturities unless we have some independentconfirmation 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 maturitymodels treat all types of kerogen identically. Despite experimental evidence indicating that differentkerogens decompose to yield hydrocarbons at different levels of maturity models, do not utilizedifferent kinetic parameters for the various kerogen types.

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

Source-rock data tor the Turquoise WellDepth Type of Atomic % Alginite(ft) Sample TOC Bit/TOC H/C Ro TAI + Exinite

3000 Cuttings 1.0 0.06 0.90 0.49 2-2.5 403500 Cuttings 0.8 0.06 0.85 0.52 2.5 304000 0.7 0.05 0.86 0.59 2.5 354500 0.9 0.08 1.02 0.65 2.5-3 405000 1.1 0.91 0.91 0.67 2.5-3 505500 2.3 0.66 1.25 0.88 2.5-3 806000 2.6 0.22 1.21 0.91 2.5-3 756500 4.1 0.51 1.17 1.00 2.5-3 757000 0.5 0.08 0.65 1.07 3.0 257500 0.3 0.08 0.71 1.27 3-3.5 408000 1.8 0.27 0.99 1.21 2.5-3 708500 1.7 0.18 1.03 1.26? 2.5-3.5 809000 0.2 0.01 0.60 1.41? 3.5 209500 0.4 0.03 0.51 1.33? 3-3,5 1510,000 0.3 0.02 0.48 1.51 3.5 10

TOC = Total Organic Carbon TAI = Thermal Alteration IndexBit/TOC = Bitumen/Total organic carbon Ro = Vitrinite reflectance? indicates a poor histogram

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

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

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

Age (Ma) Depth (m)0 0 Present-day average surface temp. 15° C2 500 Corrected BHT (4200 m): 141° C38 1200 Estimated surface temp.end Cretaceous: 25° C65 270080 3000100 4000

EXERCISE Thermal Maturity 4The Ultraviolet Well is spudded in Paleocene sediments. At a depth of 1500 ft,micropaleontology indicates the rocks to be of Maestrichtian age. The following UpperCretaceous boundaries are noted:

Maestrichtian-Campanian 1807 ftCampanian-Santonian 2002 ftSantonian-Coniacian 2360 ftConiacian-Turonian 2546 ftTuronian-Cenomanian 3017 ft

The Cenomanian is 480 ft thick and overlies 1000 ft of Kimmeridgian-age shale. Total depth isreached at 6120 ft in Middle Jurassic rocks.Evidence from related sections indicates that the Paleocene was originally about 3000 ft thickand that no other Cenozoic sediments were ever deposited. Total original thickness of theKimmeridgian is thought to be 1500 ft. It is also believed that 500 ft of Lower Cretaceoussediments were deposited before uplift and erosion began.Assuming a surface temperature of 10° C and a geothermal gradient of 2° F/100 ft, draw aburial-history curve for the section penetrated and calculate maturity for the Kimmeridgianshale.

Age datatop Paleocene 55 Ma base Turonian 91 Mabase Paleocene 65 base Cenomanian 97base Maastrichtian 73 base Cretaceous 144base Campanian 83 top Kimmeridgian 150base Santonian 87.5 base Kimmeridgian 156 Mabase Coniacian 88.5

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EXERCISE Thermal Maturity 5Analyze the timing of oil generation in the Pink Well. The geothermal gradient was found to be1.0° F/100 ft, and the surface temperature today is about 15° C. Time-stratigraphic data aregiven in the following table. No unconformities are recognized within the Paleozoic. Erosionalremoval since the Permian probably totals about 2000 ft.

Top of Age (Ma) Period Depth (ft)Permian 230 Permian 0Virgil 280 L. Carboniferous 7,000Missouri 288 '' 8,000Des Moines 296 '' 11,000Atoka 304 '' 13,000Morrow 309 '' 18,500Mississippian 320 E. Carboniferous 21,000Kinderhook 340 '' 23,000Sylvan 425 Ordovician 25,500Arbuckle 470 '' 27,500

EXERCISE Thermal Maturity 6You have been asked to evaluate an undrilled prospect in a remote area that is available in anexpensive farm-in deal. Because of the high operations cost, upper management has decided thatgas and condensate are not economical. Your responsibility is to make a recommendationregarding the nature of hydrocarbons that might be present in die prospect. The followinggeological 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. Thesource rock is thought to be about 300 Ma old. No other source rocks werenoted. Highly fractured carbonates overlie the source rock; they are in turnoverlain at 2750m by a sandstone of excellent reservoir quality. Thereservoir is sealed by a thick salt layer. No other reservoirs areanticipated.The basin filled at a generally uniform rate from about 300 Ma to 100 Ma. Atthat time nearby orogenic activity caused the first traps to be formedduring a gradual 1200m uplift lasting until 40 Ma. From 40 Ma to the presentabout 500m of additional burial occurred.Nearby well control indicates that a geothermal gradient of 3.65°C/100 m anda surface intercept of 15°C are reasonable for the area. The traps at theprospect location formed slightly prior to the beginning of erosionalremoval in the basin and have retained integrity to the present."

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

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10 - Quantitative AssessmentSo far we have been talking in rather generalized terms. However, we have to remember that we aredealing with a resource and that we are very concerned with the quantities involved. Now we mustsee how we can apply our knowledge of the geology to assessing the amounts of petroleum that wehave found, or hope to find. This section is included to give an idea of what is involved. We willrefer 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 ofknowing in advance of drilling whether or not there is going to be any oil or gas at all down thereunder 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 havefound: the geology, which controls the amounts of oil in the reservoir, is liable to change between ourinformation points, our wells. We have to try to understand, or predict, just what these changesamount to. So, until actually all of the oil has been produced, we are involved with a greater or lessdegree 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 oilcompanies, of the following terms:

OIL IN PLACEThis is the total volume of oil, measured in barrels or other units that is present in an accumulationunder the ground. It usually refers to what was there originally, before we started to take any of itout. You may see the engineers using the term STOOIP: stock tank oil originally in place. The stocktank is, in the case of small fields, located at surface near the well-head, and oil may be produceddirectly into it; and hence the STOOIP refers to the oil in place in the reservoir but corrected to thevolume it would occupy under surface pressure and temperature, and therefore without any dissolvedgas of significance. We cannot regard these quantities as `reserves', since we are never able torecover all of the oil that is down there in the reservoir.

RESERVESPerhaps the following explanations will give you some idea of what we are up against when we cometo 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 anaccumulation. We may distinguish between primary reserves that can be produced without anyartificial assistance other than pumping; secondary reserves, which can be produced using assisted orenhanced 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 muchmoney are we prepared to spend on getting it out of the ground. A bald figure for `recoverablereserves' is somewhat meaningless, unless we can be more specific about how we are going toproduce them.Because anyway there is uncertainty about this amount, it is desirable to be able to express ourdegree 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 definitionsof what is proven. Some might use the term to refer to the amount of recoverable oil that is believedto lie within a given radius, half a mile or whatever, of a well, What they think is beyond that in theaccumulation, 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 seeshortly.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 beingpresent. 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 knowwhat is meant!Original and remaining reserves: These are fairly obvious. They refer respectively to what wasthere and recoverable before we started producing, and what is still there for the taking at a givendate. Usually, if we hear simply about `reserves', it is the remaining reserves, that are meant.

DISCOVERED RESERVESOnce a discovery of oil has been made, the normal way of estimating how much has been found is tostart with the volume of the reservoir within the closure of the trap. We then eliminate progressivelyeverything from this volume that is not oil. So we multiply the bulk volume of the reservoir in thetrap by those factors that represent the non-oil.Recoverable reserves =

[BV * Fill * N/G * ? * (1 - Sw)] * RF * ConstantFVF

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 bedetermined 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 beingdiscounted. It is affected by many factors, including the adequacy of the source rock to provideenough oil to the trap, and the quality and strength of the cap rock. If we do not know where thegas-oil and oil-water contacts are, then this factor may be little more than a guess; if we do, thenwe 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 porousand permeable to contribute oil to production. We have to discount those parts of it that areuseless and just consider the net reservoir thickness. This will be controlled by variations in thenature of the sediments that comprise the reservoir, meaning that we have to try to interpret indetail the environments that the sediments were deposited in. This can be pretty subjective, evenwhen 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 entireaccumulation. We do our best from measurements on core samples and from wireline loginterpretation, but what happens between and beyond our well control?

– Sw is the water saturation, the percentage of the porosity that is occupied by the immovablewater. Again we need an average value for the field. We have not only all the problems ofaverage porosity but remember that the size of the pores comes in here as well: the finer thesand, the higher will be the water saturation.

– FVF is the formation volume factor. This reflects the fact that oil under the ground in thereservoir occupies more space than it does when we get it up to the surface; it shrinks becausegas bubbles out of it as its pressure is eased during production. We may actually be able tomeasure the FVF if we have a sample of oil collected under subsurface pressures from thebottom of our well.

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– RF is the recovery factor, the proportion of the oil in the reservoir that we can actually recoverand produce. In a sandstone reservoir, this is commonly about 50-60 per cent, but it may be agood deal less from carbonates. It is a figure that we cannot know exactly until we have finishedproducing. 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 ofoil, we have to multiply the figure we calculate by 7758. If we are working entirely in the metricsystem, then we don't have to worry.

It will be clear to anyone that, in producing figures for all of these factors, there must beconsiderable uncertainty to say the least. What we are doing, then, is to multiply uncertainties byuncertainties, doubtful estimates by doubtful estimates, until we begin to wonder whether our answerhas any reality or meaning at all. Different geologists will certainly come up with different values forat 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 escapefrom the problem; companies, and governments must have numbers that they can use for planningpurposes, even though they may be well aware that any such figures will eventually turn out to bewrong.Most commonly these days, and to try to be as honest and objective as possible, the problem istackled 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 thefactors we work out our best estimate, having regard to all of the geology; and we also specify thetotal range, from minimum possible to maximum possible, somewhere within which the `true' figuremust be. Then we get a computer to pick a value for each factor at random from the range we havegiven, but biassing its pick towards our best estimate. The computer does the sum using thesevalues. 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 intoorder 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 shallfind that the bulk of them tend to cluster round the middle (Fig.). The one that has the most answersin (= 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 theanswers (the mean).This is because, for this average value, we can work out the standard deviation(the ±) 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 successivereserve ranges is plotted against the size ranges themselves. Alternatively one may plot the frequencies aspercentages of the total number of answers: the statistical probabilities. Note that the preferred answer thatis 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 theanswers from the 100 per cent probability downwards, the curve represents the chance (probability) thatthe reserves are a certain size or greater. In the lower plot, the same values are discounted by a 50 per centrisk factor, to give the chance of discovering certain reserves or more including the 50 per cent chance thatwe may find nothing at all.

Most usefully, perhaps, we can plot out the percentages of answers in successive size rangescumulatively as we work down the list (Fig.). It will give a graph which shows the probability thatthe reserves will be of a certain size or more. This is what is used to determine those reserves thatmay be called proven, probable, and possible at, say, the 90, 50, and 10 per cent levels of probabilityrespectively. 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 tojustify development and production costs, we can read off from the graph the chances of our fieldcontaining that much oil or more; management can then decide whether or not to take the gamble ondeveloping the field at those odds. So this type of graph has now become one of the standard keytools in exploration/development decision.

UNDISCOVERED RESERVESThis is all very well, you may say, but it assumes that we have already discovered oil; it doesn't takeany account of the fact that our exploration well may, for geological reasons, turn out to be totallydry-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 thechance of there in fact being any oil at all. This chance (probability) is known as the risk factor: it isan 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 anundrilled 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 outcompletely objectively, but rather it is the number an individual geologist might produce to reflecthis/her personal interpretation of the geology; different geologists will arrive at different figures forthe probability of success. And if all this sounds like a gambling game, that is exactly what it is. It isthis 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. Theway it is commonly approached is to go back to the basic conditions for oil acumulation: all of theessential requirements have to be met if there is to be oil in a particular place and that, if any one ofthem 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 thegeological 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 reserveestimates from our Monte Carlo simulation multiplied (discounted) by the risk factor (Fig.). Thiscombines in a single estimate, the two elements of size and chance of success, and as such can bevery useful in planning an exploration program. Should we, for example, go for a large but veryrisky prospect, or would our money be better spent on drilling a smaller but safer one? The riskedreserves, however, is a hypothetical figure, and we should be on our guard against believing that it iswhat 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 issometimes called the `ultimate reserves'-a grand total for the basin.

ULTIMATE RESERVESSo far we have been talking about a single oil accumulation or a single prospect. How now do weestimate 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 anumber 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 takescare of this. However, we have to assume that today we can identify and assess all of theprospects that ever will be found in the basin; to believe that we can do this would be the heightof conceit.

2. We could adopt what is known as a `geochemical material balance' approach. This starts withthe volume of mature source rock in the basin and then, knowing how rich it is, the amount of oilgenerated, expelled, and made available for entrapment (the `charge') can be calculated. Thereare lots of uncertainties in this but the calculation would be amenable to a Monte Carlo type ofsimulation. If we have a reasonable amount of information and control, this technique may bringus 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 oilper cubic mile of sediment, or underlying each square mile of surface area; then use these figuresfor the unexplored parts of the basin.

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

5. Use past statistics (number of barrels of oil found on average for each 100m of explorationdrilling?) and extrapolate to future drilling. In a similar vein the amount of oil found world-wideeach 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 thearea under it represents the total volume of oil found to date. Extrapolate this smoothing line outinto 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 theyprefer and, for our `best estimate', merely use the average of the figures they produce. Forcingthese experts to agree a figure amongst them might refine the approach. This is known as theDelphi technique. Delphi was the place in ancient Greece where one went to consult the oracleabout 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 moreappropriate in given circumstances than the others. But we have to admit that, unless we really havea lot of information (we never have enough!), all of them are very dodgy