1

SOURCE ROCK EVALUATION

By

DR.MUHAMMAD MUJTABA

ISLAMABAD.

May 30, 2010

2

TABLE OF C O T E T S

Page

A Geochemical Approach to Basin Evaluation 1

Sample Collection 1

Source Rock Potential 2

Organic Matter 2

Depositional Setting 4

Geologic age 5

Paleo Latitudes 6

Structural Forms 7

Biologic Evaluation 8

Kerogen 12

Maturity ........................................................................................... 12

Source Rock 14

Diagenesis 14

Catagenesis 14

Total Organic Carbon (TOC) 14

Pyrolysis 15

S1, S2, S3 Peaks 16

Tmax (C) 17

Hydrogen Index (HI) 17

Source Rock Maturity Summary 18

Transformation Ratio 19

Organic Matter 19

Thermal Maturity and Hydrocarbon Generation 20

Stages of thermal maturity 21

Geochemical Modeling 22

Preservation of organic matter 23

Thermal Maturity Modeling 23

Hydrocarbon Migration 25

Resource Assessment 26

Hydrocarbon Geochemistry 28

Oil geochemistry 28

Gas geochemistry 29

3

Correlation Studies 30

Petroleum System 30

Sedimentary Basin Investigations 31

Petroleum System 31

Play and Prospect Investigation 31

Petroleum System 32

Level of Certainty 33

Pod of active source rock 33

Petroleum definition 34

Investigation Technique 34

Overburden Rock 36

Formation of Sedimentary Basin 38

Types of sedimentary basin 38

Structural and Thermal Evaluation of Sedimentary Basin 40

Source of Heat 40

Estimating Temperature and Heat Flow 41

Temperature 41

Thermal Conductivity 41

Surface temperature 42

Sedimentation 42

Groundwater Flow 42

Processes 43

Diagenesis, Catagenesis & metagenesis 43

Oil expulsion through Pyrolysis 44

Secondary migration & accumulation 45

Establishing migration direction 45

Seal 45

Subsidence history 46

Decompaction 47

Tectonic Subsidence 48

Paleobathymetric correction 48

Eustatic Correction 48

Sediment Load 48

Thermal History 48

4

Arrhenius equation 49

Pale temperature 49

Effect of thermal Conductivity 50

Effect of internal heat generation 50

Effect of Water flow 50

Indicators of formation temperature 50

Vitrinite reflectance 50

Other burial indices 51

Geothermal and Pale-geothermal signatures of basin types 51

References 78

5

List of Figures

Figure 1: Kerogene transformation coefficients (after Waples, 1980) 58

Figure 2: Thermal conductivity of common rocks. 58

Figure 03: Components of hydrocarbon supply and composition assessment. 59

Figure 4: Inert Kerogene. 59

Figure 5: Pyrolysis-gas choromatogram of lacustrine shale

(Alkesinac shale, Yugoslavia) 60

Figure 6: Pyrolysis-gas choromatogram of marine shale

(Kimmeridge Shale, orth Sea) 60

Figure 07: Pyrolysis-gas choromatogram of shale dominated by vitrinitic material

(Tertiary, Gulf of Mexico) 61

Figure 08: Pyrolysis-gas choromatogram of degraded marine organic matter

(Cretaceous, DSDP site 534). 62

Figure 09: Pyrolysis-gas choromatogram from a sample dominated

by inert kerogen. 62

Figure 10: Classification of the three main types of kerogen in a HI vs OI diagram. 63

Figure 11: HI T max diagram. 64

Figure 12 effect of weathering on various geochemical indices. 64

Figure 13: Changes in vitrinite reflectance with increasing thermal maturity. 65

Figure 14: ormal vitrinite reflectance profile from China Sea. 65

Figure 15: effect of different kinetics on hydrocarbon generation

(from Tissot et al. 1987). 66

Figure 16: Petroleum components. 66

Figure 17: Gross composition of normal producible crude

(from Tissot and Welte 1984) 67

Figure 18: Oil Classification scheme based on bulk geochemical character

(after Tissot and Welte, 1984). 67

6

Figure 19: hydrocarbons observed in modern algae (After Gelpi et al., 1970). 68

Figure 20: Effects of biodgradation on the saturated fraction of a suite of crude oil

from the iger Delta. 69

Figure 21: Summary of effects of biodegradation on chemical and physical

properties of crude oils (from Clayton, 1990) 69

Figure 22: Schematic representation of the development of sour (high sulfur)

crude oils. 70

Figure 23: Precursors for the major biomarker classes (Waples. 1985) 70

Figure 23 B: names and various ways of depicting n-alkanes (from Waples, 1985). 71

Figure 24: relationship between precursor and n-parafin distribution

(from Lijmback, 1975). 71

Figure 25: An example of the use of methane carbon isotopic composition to

determine probable source. 72

Table 1.3. Oil and Gas Fields in the Fictitious Deer-Boar (.) Petroleum system, or the

Accumulation related to One Pod of Active Source Rock. 72

Figure 26. 72

Figure 27: Burial history chart showing the critical moment (250 MA) and the time of oil

generation (260-240 Ma)for the fictitious Deer-Boar(.) petroleum system. This

information is used on the events chart (Figure 1.5). eogene () includes the

Quarternary here. All rock unit names used here fictitious. Location used for

burial history chart is shown on figures 1.3 and 1.4.

(Time scale from Palmer 1983.). 73

Figure 28: Plan map showing the geographic extent of the fictitious Deer-Boar (.)

petroleum system at the critical moment (250 Ma). Thermally immature source

rock is outside the oil window. The pod of active source rock lies within the oil and

gas windows. (Present day source rock maps and hydrocarbon shows on figure

5.12 and 5.13, Peters and Cassa, Chapter 5, this volume). 73

Figure 29: geological cross section showing the stratigraphic extent of the fictitious Deer-

Boar (.) petroleum system at the critical moment (250 Ma). Thermally

immature source roack lies updip of the oil window. The pod of active source

rock is downdip of the oil window. (The present day cross section is shown in

figure 5.12 F, Peters and Cassa, Chapter 5, this volume.) 75

7

Figure 30: the events chart showing the relationship between the essential elements and

processes as well as the preservation time and critical moment for the fictitious

Deer-Boar (.) petroleum system. eogene () includes the Quaternary here.

(Time scale from Palmer, 1983.) 74

Figure 31: Geochamical log for well 1, showing immature and mature source rocks in the

Upper and Lower Cretaceous (see tables 5.1-5.3). Mud gas data were

unavailable for this well. 75

Figure 32: Representative tectonic subsidence histories for basins from different tectonic

settings. The top graph shows the slops of a range of sedimentation rates after

compaction and is provided for reference (After Angevine et al., 1990.) 76

Figure 33: Summary of the typical heat flows associated with sedimentary basins of

various types. 77

8

THERMAL MATURITY MODELIG

Thermal maturity modeling provide the only reliable mechanism, to both, extrapolate the level of thermal maturity away from the subsurface control and estimate the timing of

hydrocarbon generation and expulsion.

Previously, all of the approaches to maturation modeling were based on the concept that specific time-temperature histories will result in a predictable level of thermal maturity

(Lopatin, 1971; and Waples, 1980). Much of this is based on empirical data which relate

present-day temperature and stratigraphic age to the observed level of thermal maturity.

At present there are two approaches to thermal maturation modeling:

1. One method is based on empirical-derived relationships between time, temperature,

vitrinite reflectance and and other apparent indices of hydrocarbon generation (Wapless,

1980). This approach is commonly referred to as the Lopatin method.

2. The second approach is more rigorous (Tissot et al., 1987; and Wood, 1988) and is based

on the extrapolation of high temperature pyrolysis (Abbot et al., 1985; Lewan, 1985,

Saxby et al., 1986; Quigley and Mackenzie, 1988 and Issler and Snowden, 1990) to

determine the kinetics (i.e. the science of the relationship between the motions of bodies

and the forces acting on them) of hydrocarbon generation (Campbell et al., 1978;

Burnham and Braun, 1985; Braun and Burnham, 1987; Burnham et al., 1987; Ungerer

and Pelet, 1987; and Zhang Youcheng et al., 1991) and the use of the Arrhenius reaction

to predict the K = Ao Exp-Ea/RT

rate of kerogene conversion. This second approach is referred to as kinetic method.

In both above noted approaches, modeling input requires burial history (including estimates the of erosion and periods of nondeposition), present and past subsurface temperature and

surface temperature history.

In the case of the kinetic method, the investigator also needs to supply the kinetic parameters, associated with the source rock (Ao the frequency factor and Ea the

activation energy). This is not required in the Lopatin method because the apparent rates of

maturation have been predefined.

The most commonly utilized Lopatin approach assumes that there is a doubling of reaction rate for each 10C

o increase in temperature (Fig. 1).

Although the calculations are different for the two models, they both rely upon the creation of a detailed burial/thermal history of the sedimentary package. This history is then used to

reconstruct the development of the maturation history and profile.

A series of sensitivity analysis has shown that the timing of hydrocarbon generation is more sensitive to the input parameters than is the absolute level of calculated thermal maturity.

Geothermal input into models can vary significantly. The simplest case assumes the utilization of a single constant geothermal gradient through time. Such simplification may be

considered generally valid in regions underlain by continental crust (excluding geothermal

regions) in old occanic crust regions (when the sedimentary section, being modeled, was

deposited late in the basins history); in regions where the crust has undergone only minor

9

amounts of extension; and if there are no major changes in the nature of the lithologic

column.

A constant geothermal gradient is, however, not appropriate in young extensional basins; in basins which has undergone substantial amounts of extensions; and in nonequilibrated

overthrust and foreland belt regions.

A constant geothermal gradient is also inappropriate if there are large contrast in the thermal conductivity, and if there is nonconductive heat transport (i.e., hydrothermal fluid flow). In

such cases, both temporal (existing in time) and down-hole changes, in the thermal gradient,

must be incorporated into the model input.

Present-day thermal information may be obtained from down-hole measurements or through the use of regional heat flow information, along with the information on the thermal

conductivity of the sedimentary section (Fig. 2).

Although both modeling approaches are capable of reproducing the present-day vitrinite reflectance profile and maturation history, only the kinetic model is able to present

information directly on the extent of kerogene conversion that has occurred. They may be

presented as a depth profile of the relative proportions of oil, gas and residue as a function of

depth or as a function of time. Such information can be presented in map view to show

regional generation pattern.

The timing of petroleum generation, expulsion and degradation is important when placed in context with the timing of trap development. It is possible that if trap development followed

oil generation, the trap would be barren.

Once the regional thermal maturity framework is established and the distribution of source rocks is known, these data can be integrated to outline the generative portions of the basin.

These are the portions of the basin where source rocks either are presently generating or

have in the past generated hydrocarbons.

It is only the volume of source rock, within the generative basin, that contributes to the overall basins resource base.

GEOCHEMICAL MODELIG

Unfortunately, hydrocarbon source rocks are not generally sampled while drilling a well; and if sampled either in outcrop or in the subsurface, are commonly immature.

This is because of two factors: 1) most drilling targets are associated with high energy depositional environment, while source rock systems develop within low energy systems; 2)

source rocks encountered either in the subsurface or in outcrop, have not usually

experienced the most favourable burial history for the generation of hydrocarbons.

Wells are generally drilled on structural highs above the oil-window rather than within the generative deeps within a basin.

At the same time, outcrop localities tend to be often located along basin margins or flanks, once again away from the regions that experienced the most favourable burial history for oil

and gas generation.

10

This lack of sample control has resulted in the development of a series of geochemical models that qualitatively predicted the distribution of oil and gas prone source systems, and

quantitatively predict the level of thermal maturation and degree of hydrocarbon generation.

A GEOCHEMICAL APPROACH TO BASI EVALUATIO

The primary job function of a petroleum explorationist is to utilize all the available data to reduce the risks associated with petroleum exploration. Such an analysis requires a fully

integrated approach using many aspects of geoscience.

In practice, however, in petroleum exploration there has been commonly an emphasis on predicting hydrocarbon trap capacity. This is largely accomplished through the use of

seismic reflection data to define the volume of rocks under closure (prospect generation).

This estimate is further refined by assuming a net reservoir thickness and an average porosity. Petroleum engineers are commonly given this information along with largely

arbitrary fill-up factors to assess exploration economics.

This is interesting to note that nowhere in this approach there has been any attempt to determine the amount and type of hydrocarbons that actually may be available for

entrapment.

Organic geochemistry is the only effective means of directly addressing the problems associated with the amount and nature of the reservoired fluids.

The determination of the characteristics of the reservoired fluid is accomplished by examining the richness, organic geochemical character of the various source sequences and

the level of thermal maturity of the various source and reservoir sequences within a basin.

These geochemical attributes are commonly measured directly. However, because of the limited number of wells as well as the geologic settings of both surface and outcrop samples,

analytical data needs to be supplemented by geologic and numeric modeling results (Fig. 3).

ORGAIC MATTER

Oil-prone organic matter appears as distinct algal bodies, plant cuticle, spores and pollen grains and fluorescent amorphous material. The fluorescent amorphous material is believed

to have been derived by the bacterial reworking of algal material.

Gas-prone organic matter appears as woody structural material (vitrinite) or as nonfluorescent amorphous material.

Nonfluorescent amorphous material may be derived either as a result of an advanced level of thermal maturity (Ro greater than 0.9%) of originally fluorescent amorphous material, or

through the bacterial or fungal degradation of structured organic matter.

11

Inert organic matter usually appears as black, structured organic matter in transmitted light and highly reflective under reflected light. Much of this material has either been recycled or

severely oxidized prior to its final deposition (Fig. 4).

Although the above mentioned methods provide some information on oil or gas proneness, they do not provide detailed information on the actual character of the generated

hyrocarbons. More detailed information, however, can be obtained through the use of

pyrolysic-gas chromatography.

In simple terms, in pyrolysis-gas chromatography, a sample is heated in an inert atmosphere. The generated products are collected using a cold trap. These hydrocarbons are then

introduced in a gas chromatographic column for analysis. It is important to note that these

products are similar but not identical to naturally occurring products. The primary difference

is that the pyrolysis products contain substantial amounts of unsaturated hydrocarbon

compounds.

Pyrolysis-gas chromatographic results can be used either qualitatively or quantitatively. Qualitatively the chromatographic fingerprints are compared to a set of known signatures to

establish depositional environments, to assess the oil versus gas proneness and to determine

the relative waxiness of the generated products.

A series of such standard or typical chromatographic fingerprints is presented below:

Locustrine samples produce chromatograms dominated by alkene-alkene doublets (Fig. 5). The samples contain significant quantities of waxy C22

+) compounds. The chromatographic

fingerprints are grossly similar for both carbonates and shales. There are, however, some

differences, which are largely manifested in the normalized alkane-alkene distribution and

can be related to differences in the original biomass.

Samples containing well-preserved marine organic matter display chromatographic patterns which include significant naphthenic envelopes, a well-defined series of alkane-alkane

doublets, which exhibit a harmonic decrease with increasing carbon number (Fig. 6).

Samples, dominated by vitrinite, produce chromatographic patterns which include abundant aromatic compounds as well as significant contributions by various phenolic compounds

(Fig. 7).

Samples, containing poorly preserved marine organic matter, produce chromatograms with poorly defined peaks (Fig. 8).

It is important to note that neither Rock-Eval pyrolysis nor elemental analysis could effectively differenciate between type III organic matter derived from terrestrial or marine

sources.

Samples dominated by inert organic produce chromatograms that are little more than a baseline trace (Fig. 9).

Quantitatively, pyrolysis-gas chromatography results are interpreted by comparing the relative abundance of C1-C5, C6-C14 and C15

+ fractions. The relative abundance of these

compounds establishes the oil-versus gas-proneness of the organic matter as well as its

tendency to generate waxy products.

Petroleum classification or gross composition can also be inferred using the relative abundance of aromatic, n-alkyle and resolved unknown compounds.

12

Organic Matter

There is now a wealth of geochemical evidence that petroleum is sourced from biologically derived organic matter buried in sedimentary rocks.

Organic-rich rocks, capable of expelling petroleum compounds, are known as source rocks.

Source beds form when a very small proportion of the organic carbon, circulating in the Earths carbon cycle, is buried in sedimentary environments where oxidation is inhibited.

The carbon cycle is initiated by photosynthesizing land plants and marine algae, which convert carbon dioxide present in the atmosphere and seawater into carbon and oxygen

using energy from sunlight. Carbon dioxide is recycled back in many ways, such as: i)

animal and plant respiration (bringing carbon dioxide back to the atmosphere), ii) bacterial

decay and natural oxidation of dead organic matter, and iii) combustion of fossil fuels (both

natural and by man).

From petroleum geology point of view, the small proportion of carbon, which escapes from the cycle as a result of deposition in such sedimentary environments where oxidation to

organic matter is limited, is important. Such environments are generally depleted in oxygen,

such as, some restricted marine basins, deep lakes and swamp environments, which are toxic

for bacteria.

Petroleum is, therefore, sourced from organic carbon that has dropped out of the carbon cycles at least for some time. It, however, rejoins the cycle when extracted by man and

combusted.

Much of the worlds oil has been sourced from marine source rocks. Source beds may develop in enclosed basins with restricted water circulation (reducing oxygen supply) or on

open shelves and slopes as a result of upwelling or impingement of the oceanic midwater

oxygen-minimum layer.

In the world oceans, simple photosynthesizing algae (phytoplankton) are the main primary organic carbon producers. Their productivity is controlled primarily by sunlight and natrient

supply.

The zones of highest productivity are in the surface waters (euphotic zone) of continental shelves (rather than open ocean) in equatorial and mid latitudes, and in areas of oceanic

upwelling or large river input.

The productivity of land plants is controlled primarily by climate, particularly rainfall. Coals have formed in the geological past predominantly in the equatorial zone and in cool wet

temperate zone centered at about 55o (N and S).

All living organic matter is made up of varying proportions of four main groups of chemical compounds. These are carbohydrates, proteins, lipids and lignin.

Only lipids and lignin are normally resistant enough to be successfully incorporated into sediment and buried.

Lipids are present in both marine organisms and certain parts of land plants, and are chemically and volumetrically capable of sourcing the bulk of the worlds oil.

13

Lignin is found only in land plants and cannot source significant amounts of oil, but is an important source of gas.

Geochemical studies of coal macerals have shown a very significant oil potential among the exinite group, comprising material derived from algae, pollen and spores, resins and

epidermal tissue.

The organic compounds, provided to the sea bottom sediments by primitive aquatic organisms, have probably not changed dramatically over geological time.

In contrast, however, important evolutionary changes have taken place in land plant floras. As a result, a distinction can be made between the generally gas-prone Paleozoic coals, and

the coals of the Jurassic, Cretaceous and Tertiary, which may have an important oil-prone

component.

Anoxic conditions (oxygen-depleted) are required for the preservation of organic matter in depositional environments, because they limit the activities of aerobic bacteria and

scavenging and bioturbating organisms which otherwise result in the destruction of organic

matter.

Anoxic conditions develop where oxygen demand exceeds oxygen supply. Oxygen is consumed primarily by the degradation of dead organic matter; hence, oxygen demand is

high in areas of high organic productivity.

In aquatic environments, oxygen supply is controlled mainly by the circulation of oxygenated water, and is diminished where stagnant bottom waters exist.

Other factors are: the transit time of organic matter in the water column from euphotic zone to sea floor, sediment grain size, and sedimentation rate which effect source bed deposition.

Depositional Settings

The three main depositional settings of source beds are lakes, deltas and marine basins.

Lakes are the most important setting for source bed deposition in continental sequences. Favourable conditions may exist in deep lakes, where bottom waters are not disturbed by

surface wind stress, and at low latitudes, where there is little seasonal overturn of the water

column and temperature-density stratification may develop. In arid climates, a salinity

stratification may develop as a result of high surface evaporation losses.

Source bed thickness and quality is improved in geologically long-lasting lakes with mineral clastic input.

Organic matter on lake floors may be autochthonous, derived from fresh water algae and bacteria, which tends to be oil-prone and waxy, or allochthonous, derived from land plants

swept in from the lake drainage area, which may be either gas-prone or oil-prone and waxy.

The Eocene Green River Formation of the western USA, and the Paleogene Pematang rift sequences of central Sumatra, Indonesia are examples of rich, lacustrine source rock

sequences.

Deltas may be important settings for source bed deposition. Organic matter may be derived from freshwater algae and bacteria in swamps and lakes on the delta-top, marine

14

phytoplankton and bacteria in the delta-front and marine pro-delta shales and probably most

important, from terrigenous land plants growing on the delta plain.

On post-Jurassic deltas in tropical latitudes, the land plant material may include a high proportion of oil-prone, waxy epidermal tissue. Mangrove material may be an important

constituent.

Examples of deltaic source rocks include the Upper Cretaceous to Eocene Latrobe Group coals of the Gippsland basin, Australia.

Much of the worlds oil has been sourced from marine source rocks. Source bed may develop in enclosed basins with restricted water circulation (reducing oxygen supply), or on

open shelves and slopes as a result of upwelling or impingement of the oceanic midwater

oxygen-minimum layer.

Examples of modern enclosed marine basins include the Black Sea and Lake Maracaibo. Source bed deposition is favoured by a positive water balance, where the main water

movement is a strong outflow of relatively fresh surface water, leaving denser bottom-

waters undisturbed.

The Upper Jurassic Kimmeridge Clay Formation of the North Sea, and Jurassic Kingak and Aptian-Albian HRZ Formations of the North Slope, Alaska, are examples of source rocks

deposited in restricted basins on marine shelves.

The time of oil and gas generation cannot always be equated with the time of trapping. Under certain conditions, generated oil can be retained in source rocks for a long time. This

situation may occur when source rock is separated from reservoir rock by an impermeal seal.

This oil can be released later due to fracturing of the seal caused by tectonic and other

processes.

More than 90% of original recoverable oil and gas reserves in the world has been generated from source rocks of six stratigraphic intervals, which represents only one-third of

Phanerozoic time. The six stratigraphic intervals are 1) Silurian (generated 9% of the

worlds reserves), 2) Upper Devonian-Tournaisian (8% of reserves), 3) Pennsylvanian-

Lower Permian (8% of reserves), 4) Upper Jurassic (25% of reserves), 5) Middle Cretaceous

(29% of reserves), and 6) Oligocene-Miocene (12.5% of reserves).

This uneven distribution of source rocks in time displays no obvious cyclicity and the factors that controlled the formation of source rocks vary from interval to interval.

There are several primary factors which controlled the areal distribution of source rocks, their geochemical type and their effectiveness (i.e., the amounts of discovered original

conventionally recoverable reserves of oil and gas generated by these rocks). These factors

are geologic age, paleolatitude of the depositional areas, structural forms (basin

configurations) in which the deposition of source rocks occurred, and the evolution of biota.

Geologic Age

Jurassic was a time of exceptionally warm climates that presumably permitted favourable oil-prone rock development even in high latitudes in the North sea, West Siberia and

possibly even Antarctica.

15

The most important change in the character of source rocks, during the Phanerozoic, was the appearance and expansion of source rocks containing type III Kerogene and Coal. The

effectiveness of these source rocks also grew, reaching its maximum in the Oligocene-

Miocene.

A significant increase in areas of type III Kerogene and coal is accompanied by a relative decrease in areas covered by Kerogene type I and II rocks. Rocks with type I kerogene are

rare and are insignificant, as according to latest analysis, they have provided approximately

2.7% of the original reserves of world petroleum.

With the expansion of source rocks, containing type III kerogene, there seams to be gradual elimination of marine environments favourable for deposition of facies enriched in

sapropelic (type II kerogen) organic matter, primarily the black shale facies.

Paleo latitudes

A warm, moist climate, characteristic of low to middle paleolatitudes, supports abundant life, such as very highly bioproductive tropical rain forests on the land and reef communities

on the continental shelf. This climate is believed to be favourable for source rock deposition.

Study shows that areally two-thirds of the source rocks of the above noted six principal stratigraphic intervals were deposited between the paleoequator and 45-degree

paleolatitudes.

Low latitudes were more favourable for deposition of source rocks with kerogene types I and II. In contrast, more source rocks containing kerogene type III and coal were deposited

in high latitudes (except for the Oligocene-Miocene interval).

A very high effectiveness of source rocks with kerogene types I and II, deposited in low latitudes, is connected with the widespread presence of carbonate reservoir rocks and

evaporite seals that helped trap and retain petroleum.

Beginning in the Late Jurassic, source rocks with kerogene types I and II became noticeably more common in high latitudes. Deposition and preservation of organic matter in high

latitudes were probably helped by the globally warm Mesozoic climate. Black shale facies

of this age extended over large areas of Arctic seas.

A very different areal distribution is, however, the characteristic for source rocks that contain dominant type III kerogene and coal. These source rocks appeared in minor amounts

in the Late Devonian-Tournoisian at low latitudes. In the Pennsylvanian-Early Permian and

Mesozoic, the largest depositional areas of potential source rocks with type III kerogene and

coal were located in high paleolatitudes. During Tertiary, however, source rocks with type

III kerogene and coal again were deposited mostly at low paleolatitudes and primarily in

large deltas.

Note: It may be noted that the causes of this distribution, of kerogene types I, II and III, are not

exclusively biologic.

- Very little organic matter is usually found in sediments of the ecologically most favourable

zones, such as, reefs. In contrast, deposition of black shales was aided by the extremely

16

abundance of a limited number of forms, commonly blue-green algae (cyanobacteria) and

green algae.

- Other factors are also important, such as, higher reproduction rates (and thus higher

bioproductivity), especially in winter, and the absense of a seasonal overturn of water in

hydrologically stagnant basins, which favour deposition and preservation of organic matter

in tropical and subtropical seas.

- On land, great bioproductivity is characteristic of tropical rain forests; however, peat bogs

and other accumulations of organic material are uncommon there because of the high rate of

organic matter decomposition.

- Only for source rocks with kerogene types I and II, deposited in low paleolatitudes, the

effectiveness greatly exceed the areal extent, as compared to the effectiveness of source

rocks with type III kerogene.

- Similarly, the quality of kerogene types I and II in source rocks of high paleolatitutdinal

zones (e.g., North Sea, West Siberia) is very good.

- The higher effectiveness of source rocks with kerogene types I and II in low paleolatitudes is

connected to the high reservoir capacity of widespread carbonate reservoir rocks, besides the

siliciclastic reservoirs. Whereas, in polar and subpolar regions, only siliciclastic rocks are

potential reservoirs, and many of them are characterized by dirty lithology.

- An additional important factor is the widespread presence of evaporite seals in low

paleolatitudes.

- Black shale facies, with type II kerogene, carbonate (and specially reefal) reservoir rocks,

and overlying evaporites commonly were genetically and spatially related. This close

relationship resulted in a high endowment of oil and gas.

- A genetic and spacial connection does not exist among siliciclastic reservoir rocks, seals and

source rocks with type III kerogene and coal. This is why the effectiveness of these source

rocks, whether deposited in low or high paleolatitudes, does not vary significantly.

Structural Forms

Structural forms, reflecting tectonic stages in basin development, affect source rock deposition.

The structural development resulted in the formation of characteristic types of relief, appearance of sources of clastic material and rates of subsidence and sedimentation.

Development of most basins passed through different tectonic stages. These tectonic stages are expressed as successive structural forms, which existed during the corresponding time

interval.

The number of basic structural forms is limited, although the size of individual structures can vary significantly. The basic structural forms are: 1) platforms, 2) circular sags, 3) linear

sags, 4) rifts, 5) foredeeps, 6) half sags, and 7) deltas.

Each structural form is characterized by the morphology of a sedimentary body deposited in the structure.

Platforms are areally large sheets of relatively thin sedimentary rocks on cratons and less commonly, on accreted zones (epiplatforms) that dip gently toward the ocean.

17

Circular sags commonly are larger than linear sags and overlie branching rift systems or fill depressions over basaltic windows in continental crust.

Linear sags are strongly elongated depressions with gently sloping limbs and most commonly overlie single rifts.

Half sags are asymmetric sedimentary bodies composed of the seaward prograding wedges of clastic rocks and carbonate bank sediments.

Rifts are linear horst and graben depressions bounded by deep-seated faults.

Foredeeps are asymmetric troughs developed between an orogenic belt and a foreland, and are largely filled with molasse deposits derived from the orogen.

In this study, deltas are very thick sedimentary bodies located on the continental margins (commonly along a triple junction). Some deltas are similar to half sags, but because of great

sedimentary loading, deltas commonly develop partly closed central sag.

Three, out of the above noted seven structural forms, are responsible for the bulk of oil and gas reserves. Source rocks, deposited in these three structural forms, i.e., platform, circular

sags and linear sags, provided more than three-quarters of original reserves generated from

the six principal intervals.

Effectiveness of source rocks with type III kerogene and coal varies little in different structural forms, whereas analogous variations for source rocks with kerogene types I and II

is very significant.

Petroleum reserves, generated by type I kerogene, are not large; they constitute approximately 2.7% of original petroleum reserves.

It may be thus concluded that structural forms controlled primarily the deposition of source rock with type II kerogene, which is dominantly black shale facies.

Deposition of black shale facies occurred chiefly under anoxic and dyoxic conditions. Thus, over geologic time, these conditions occurred preferentially on platforms and in circular and

linear sags; less commonly these conditions formed in rifts and foredeeps, very rarely in half

sags and almost never in deltas.

Deposition of effective source rocks on platforms occurred primarily in the Silurian and Late Devonian-Tournaisian.

In the Late Jurassic and Middle Cretaceous, the principal effective source rock deposition was controlled by linear and circular sags.

Half sags and deltas controlled source rocks deposition only during the Oligocene-Miocene.

The bulk of the effective source rocks in rifts and foredeeps was deposited during the Pennsylvanian-Early Permian and the Oligocene-Miocene, which correspond to the

climaxes of the orogenics.

Note: It may be mentioned over here that tectonics does not completely account for the changed

role of various structural forms in source rock deposition through time. It is suggested that

one of the important causes of this change was the evolution of life.

18

Biologic Evolution

The significance of biologic evolution for oil and gas genesis is poorly understood. Only the development of higher land plants during the middle Paleozoic, resulting in the appearance

of terrestrial organic matter as a new source for oil and gas, is commonly referred to.

Each ecologic community, since at least the late Proterozoic, consists of producers (photosynthetic plants), consumers (animals) and decomposers (aerobic and anaerobic

bacteria and saprophytes).

In the oxic marine environment, the bulk of organic matter is consumed by metazoans, and the role of bacteria decomposition is limited.

In the anoxic environment, consumers are absent and all the organic matter is subjected to bacterial decomposition. However, the anaerobic bacterial decomposition does not result in

complete oxidation of organic matter. Its more stable components, such as lipids, tend to

accumulate in sediments.

In the terrestrial conditions, much of bioproduction (e.g. wood) is not digestable for most animals and is decomposed by aerobic bacteria and saprophytic plants.

The amount of organic matter buried in marine sediments depends little on the rate of bioproduction. This amount is controlled primarily by the balance between bioproduction

and destruction (consumption and decomposition) of organic matter.

In many highly bioproductive areas, such as upwelling zones, the amount of organic matter is sediments is insignificant. In contrast, many black shale facies were deposited under

conditions of low bioproductivity.

The inorganic oxidation of organic matter, as compared to the biologic destruction, is highly inefficient. Therefore, the amount and quality of deposited organic matter depend on the

activity of consumers and decomposers. At present, this activity (excluding anaerobic

bacteria) is regulated by the availability of oxygen at and near the sediment surface, and the

deposition of marine black shale facies with type II kerogene occurs primarily on oxygen

depleted sea bottom.

There are, however, many indications that in the late Proterozoic-early Paleozoic, deposition of organic-rich rocks commonly occurred not only under anoxic but also dyoxic and even

oxic conditions.

A very shallow-water carbonate and even reefal oxic environment was suitable for deposition of source rocks in the late Proterozoic. In many regions, stromatolitic dolomites

are rather rich in organic matter. These dolomites are source rocks for oil and gas fields and

shows and for bitumen deposits in China, northern Siberian Craton and eastern Russian

Craton.

Organic-rich stromatolitic carbonate rocks have not, however, been formed since the Cambrian.

The deposition of abundant organic material under oxic and dyoxic conditions during the late Proterozoic to middle Paleozoic may indicate that consumers and decomposers did not

fully use oxygen and organic matter as the available energy source.

19

Worms and other soft-bodied burrowing animals are the major consumers of organic matter in the upper layer of sediments.

During the late Paleozoic and Mesozoic, black shale facies were restricted chiefly to relatively deep-water (commonly below a few hundred meters), semi-enclosed basins

separated from the open sea by structural barriers or reefs. Linear and circular sags and to a

lesser extent, rifts were the most favoured for formation of these basins.

Beginning from the latest Cretaceous, the major black shale deposits were formed in deep, almost completely isolated, euxinic basins. The principle basins of this type were formed in

depressions of the Alpine fold belt and in some rifts.

In the semi-enclosed silled basins, the black shale facies was essentially replaced by organic-lean Globigerina ooze.

The flourishing of planktonic foraminifers, that began in the Late Cretaceous, could have significantly decreased the bioproduction because the foraminifers fed mainly on

phytoplankton.

The evolution of diatoms that flourished in the Tertiary was also significant for deposition of source rocks. Diatoms have an extremely high lipid content that reaches 40% of their

weight.

The evolution and expansion of terrestrial plants, after the Silurian, brought about a new source of organic matter.

Until the Permian, plants primarily occupied seashores, resulting in the dominance of paralic coals. Limnic coals first appeared in the Late Carboniferous, but became widespread in the

Mesozoic and reached their maximum abundance in the Tertiary.

The Mesozoic forestation of vast land areas resulted in the appearance of forest lakes surrounded by swamps. These lakes were ephemeral and quickly became bogs with peat

deposition. Resulting coal-bearing deposits contain lacustrine beds rich in alginite (gyttja)

and are an oil source in generally gas-prone sequences.

The evolutionary changes in plants and the inland expansion of forests account for the increasing proportion of oil in petroleum, generated from source rocks with dominant type

III kerogene and coal from the late Paleozoic.

However, the variety of environments favorable for formation of source rocks with type II kerogene decreased significantly. This decrease brought about the gradual diminishing of

the role of marine black shale facies as the most important generator of petroleum. The

black shale facies were essentially replaced by source rocks with type III kerogene and coal.

Eustatic transgressions, Global Climate and Ocean Hydrodynamics are believed to affect source rock deposition.

Climatic control on deposition of continental source rocks with type I and type III kerogene is well known.

Worldwide transgressions caused by deglaciation and changes in the ocean topography cover large continental areas. Transgressions are believed to be highly favourable for black

shale deposition in continental basins. The depositional model includes global warming,

weak ventilation of oceans by oxygen-rich polar water, expansion of the oxygen-deficient

layer, and its impingement on the continental slopes and shelves.

20

Many widespread black shales, on shallow shelves, were deposited during geologically short periods of time. In many regions, only one black shale interval is present in the geologic

column.

The Pacific and south Gondwana realms are relatively poor in oil and gas. Much of the petroleum in both realms is high-wax oils resulting from either type I and type III kerogene.

The deposition of thick Alpine molasses played the major role in burial and maturation of source rocks. Thus, the majority of oil and gas is very young. About two-thirds of original

petroleum reserves was generated and trapped during the last 80-90 m.y., a rather short

interval of the Phanerozoic geologic history.

It is significant that a large portion of the recoverable petroleum resources are found in only a few selected localities.

It is believed that, worldwide recoverable conventional oil and gas, exist in ultimate quantities approximating 2300 billion barrels of oil and 12,000 trillion cubic feet of gas.

The source rock deposition was aided by the successive opening and collisional closing of proto-Tethys, paleo-Tethys and new-Tethys that developed rift/sag structural forms

favourable for the formation of silled basins. The Tethyan basins were developed over less

than one-fifth of the worlds land and continental shelves, yet they contain over two-thirds

of the original petroleum reserves.

Unconventional resources, such as extra heavy oils, bitumen, tar sands, gas in tight sands and coal bed methane, are present in large-quantities. They are, however, expensive to

recover at adequate rates of production and sometimes expensive to alter the quality

necessary for modern day use. We dont know at present that how, if, or when they will

become major components of world energy consumption.

Similarly, natural gas hydrates, which occur widespread and in potentially recoverable large quantities, will ever prove to be a commercial source of energy.

Proved Reserves of oil are generally taken to be those quantities which geological and engineering information indicate, with reasonable certainty, can be recovered in the future

from known reservoirs under existing economic and operating conditions.

No new discovery areas have evolved to alter the broad distribution of world oil and gas resources. The Middle East, North America and the former Soviet Union still account for

about 75 percent of world petroleum resources.

It is believed that paleoclimate conditions, within the 30o latitude boundaries, surrounding the equator, are the most favourable for source rocks, carbonate reservoir rocks and Salt

seals. Accordingly, most oil and gas have been found and will continue to be found in the

geologically equatorial Tethyan Realm.

The Boreal Realm to the north, because of its Paleozoic equatorial plate tectonic position, likewise is rich in oil and gas, but the South Gondwana Realm continents have poor

properties of oil occurrence owing to the long history of high-latitude geographic association

with Antarctica.

The Pacific rim doubtless experienced climatic effects but, more important, overriding tectonic subduction events destroyed most of the stratigraphic column and introduced

volcanic debris into potential reservoir porosity, thus limiting the oil and gas occurrence.

21

In variance to the hypothesis, however, gas prone source rock are viable in intermediate to high latitudes and furthermore, Jurassic was a time of exceptionally warm climates that

prisumably permitted favourable oil-prone source rock development even in high latitudes,

i.e., in North Sea, West Siberia and possibly even Antarctica.

The northwest coast of Australia, favourably located in the Tethyan Realm, continues to contribute important discoveries from North Sea type Jurassic graben situations.

The basic petroleum system in Southeast Asia and East China of graben controlled locustrine source rock development, in early Tertiary time, feeding younger and older

reservoirs, continues to account for significant discoveries of both oil and gas in new

trapping conditions through the use of 3-D seismic imaging.

The west coast of Africa, from Nigeria south to Angola and the South Asian states of Pakistan, India and Myanmar remain steady, if modest, contributors to world petroleum

discovery.

Likewise, in the Middle East, Syria and Yamen serve to broaden the distribution and market availability of petroleum.

The Mediterranean Sea area is filled with a thick sedimentary section sealed by Miocene Messina salt. Owing to deepwater and the low price of oil, only a few exploratory wells

have been drilled and the stratigraphy is poorly known. The area has a very complex

tectonic history; it is underlain by an unknown amount of oceanic crust and an unknown

extension of the African continental platform.

SOURCE ROCK

Source rock is defined as a unit of rock that has generated oil or gas in sufficient quantities to form commercial accumulations.

Limited source rock is defined as a unit of rock that contains all the prerequisites of a source rock except volume.

Source rock cannot be defined by geochemical data alone but requires geological information as to the thickness and aerial extent.

Potential source rock is a unit of rock that has the capacity to generate oil or gas in commercial quantities but has not yet done so because of insufficient catagenesis (thermal

maturation).

The distinction between source rocks and potential (immature) source rocks are essential in petroleum system studies and when correlating oils to their source rocks.

Active source rock is a source rock that is in the process of generating oil or gas. The distribution of active source rock is essential in petroleum system studies. Active source

rock cannot occur at the surface, as they required adequate burial depth to generate oil or

gas.

22

Inactive source rock is a source rock that was once active but has temporarily stopped generating oil or gas prior to becoming spent. Inactive source rocks are usually associated

with areas of overburden removal and will generate hydrocarbon again if reburied.

Spent source rock is a source rock that has completed the oil and gas generation process. A spent oil source rock can still be an active or inactive source for gas.

source rock potential

The organic origin of oil and gas is now largely undisputed.

Rocks capable of generating and expelling commercial quantities of hydrocarbons must contain elevated levels of organic matter.

The requirement for an elevated level of organic enrichment is due to the need to saturate the source rock pore network with hydrocarbons for expulsion to occur.

A statistical study of fine-grained sedimentary rocks suggests that in order for a rock to be considered organically enriched and a possible hydrocarbon source, it must contain at least

1.0 wt% organic carbon; although this value is greater than that has commonly suggested in

the literature.

The richness or petroleum-generating potential of source rock can be determined by measurements of total organic carbon (TOC) and the pyrolysis yield.

Before describing the techniques of measurements of TOC and pyrolysis, let us first look into the organic matter.

Diagenesis

Diagenesis is the process of converting living organic material in sediments into kerogene. It involves biological, physical and chemical alteration at temperature upto 50C

o (122F

o). It

proceeds thermal oil and gas generation which is called catagenesis.

Catagenesis

Catagenesis is the process by which organic material in sedimentary rocks is thermally altered, by increasing temperature, resulting in the generation of oil and gas. Catagenesis

covers the temperature range between diagenesis and metagenesis, approximating 50Co to

200Co (122F

o to 392F

o).

Total organic carbon (toc)

The ability of a potential source rock, to generate and release hydrocarbons, is dependent upon its contents of organic matter, which is evaluated by Total Organic Carbon (TOC).

TOC is expressed as weight percent of organic carbon present in the potential source rock.

23

TOC of a rock is a direct measure of its organic richness. Sufficient quantity of organic matter must be present in a sedimentary rock before it is qualified as a potential source rock

for subsequent hydrocarbon generation.

In general, higher the concentration of marine organic matter, the better the source potential. Shales containing less than 0.5% TOC and carbonate with less than 0.2% TOC are generally

not considered as a source rock and no further analysis is performed on these samples.

TOC is easy to measure. The dried rock samples are crushed and treated with HCL to remove carbonates. After acid treatment, the sample is subjected to oxidation, so that

remaining non-carbonate carbon is converted to CO2 or CO.

Pyrolysis

Pyrolysis, from the Greek word Pyro (fire) and lysis (dissolution), is the thermo-chemical decomposition of a substance in the absence of oxygen.

Pyrolysis of rocks, kerogenes and asphattenes form the basis of many laboratory procedures, including Rock-Eval pyrolysis, pyrolysis/gas chromatography, and hydrous or anhydrous

pyrolysis.

Through pyrolysis, organic compounds are released in two stages. In the 1st stage free hydrocarbons present in the rock (S1) are released and in the 2nd stage, volatile

hydrocarbons formed by thermal cracking are released (S2).

The most widely used equipment is Rock-Eval. It is used to estimate three geochemical parameters:

1. The S1 peak represents the amount of free hydrocarbons at 300Co S1 peak is expressed in

my HC/g of rock.

2. The S2 represents the hydrocarbons generated by thermal cracking of kerogene at

temperature range of 400-800Co. S2 peak is also expressed in my H/g of rock.

3. The S3 peak represents the amount of CO2 produced from kerogene. It is collected at a

temperature range 300-390Co. S3 peak is expressed in my CO2/g of rock.

4. The organic carbon remaining after the recording of the S2 peak, is measured by

oxidation under air (or oxygen) atmosphere at 600Co. The CO2 obtained is the S4 peak,

which is expressed in mg CO2/g of rock.

Note: TOC is computed from peaks S1, S2 and S4..

The Rock-Eval method, used at the well site, is known as Oil Show Analyzer (OSA)

divide S1 peak into So peak - which records gaseous hydrocarbon trapped in the rock

matrix and which are volatized at 90Co for 2 minutes; and free liquid hydrocarbons, i.e.,

S1 peak.

The organic matter of sediments is usually divided into bitumen (soluble in organic solvent) and kerogene (insoluble residue).

24

Bitumen contains free hydrocarbons ranging from C1 to C40, heavy hydrocarbons and NSOs grouped into resins and alphaltenes.

S1 peak represents hydrocarbons ranging from C1 to C33; whereas heavier hydrocarbons, resins and asphaltenes are minor contributor to S2 peak.

Gaseous hydrocarbons (C1-C7) recorded as the So peak on OSA, are rapidly lost.

In nature, kerogene is progressively cracked during its thermal evolution, generating hydrogen rich hydrocarbons, which may be expelled from the rock; while the residual

kerogene is depleted of its hydrogen and becomes more and more condensed untill a sub-

graphitic stage is attained, i.e., when no more hydrogen is available. Thus the initial

elemental composition of a kerogene determines its ability to generate hydrocarbons.

S2 peak represents most of the hydrocarbons coming from the primary cracking of kerogene, however, it also includes hydrocarbons from the thermo-vaporization and primary cracking

of heavy hydrocarbons, resins and asphaltenes. They represent the total amount of oil and

gas a source rock can still produce during subsequent complete thermal maturation in an

open system.

S2 gives a reasonable evaluation of the current potential of a rock sample i.e., amount of oil and gas which can be generated from its present stage of thermal maturation to the graphite

stage.

S2 value depends upon the type of organic matter, the TOC of the sediment and the thermal evolution it has undergone. For immature organic rich sediments, values of 10 to 500 mg

HC/g rock were reported.

Coals give S2 peaks ranging from 50 to 500 mg HC/g of rock. It has been noted, through experience, that immature source rocks, which give S2 peaks higher than 5 mg HC/g rocks,

can be considered as fair potential source rocks.

Note: Pyrolysis of immature organic matter has shown that 70-80% of type I kerogene, 45-50%

of type II and only 10-25% of type III kerogene are transformed into hydrocarbons mostly as

an S2 peak.

S2 decreases when the thermal evolution of a source rocks increases.

The shape of the S2 peak can also be a useful diagnostic tool, especially when the interpretation of the Rock-Eval parameter is ambiguous. The S2 peak is very narrow and

symmetrical for type I organic matter, still symmetrical for type II, but quite wide for type

III organic matter.

S3 peak

- During pyrolysis, oxygen-containing compounds are quickly decomposed into

hydrocarbons, water and a mixture of CO and CO2.

- Water released from the organic matter cannot be measured in a rock sample due to thermal

decomposition of some minerals (such as clays, hydroxides, gypsum etc) too, which

generate water.

25

- S3 peak is recorded below 400Co because of the early decomposition of some carbonates,

such as, siderite and some other poorly crystallized species. However, calcite and dolomite

are decomposed close to 600Co.

- S3 depends upon both the type of organic matter and its thermal maturity. It is higher for

immature humic type III rocks, but decrease rapidly with an increasing thermal evolution as

the oxygenated functional groups (carbonyl, hydroxyl, etc) are easily decomposed. S3 is low

for types I and types II kerogene.

- When organic matter is already mature (Ro 2%), the 600Co combustion is not complete and

S4 peak gives lower value than it should be.

Tmax

Tmax is the temperature which is recorded for the maximum of S2 peak, and varies as a function of the thermal maturity of the organic matter.

Mature organic matter, which is more condensed, is more difficult to pyrolyze and requires a higher activation energy i.e., higher temperature. In fact, chemical bonds, that survived in

most highly mature kerogenes, are those which require higher energy to be broken.

Tmax is linked to the kinetics of the cracking of organic mater. Types I and type II kerogenes are known to have relatively simpler molecular structures than type III. It requires

a narrower distribution of cracking activation energies and a smaller temperature range.

An example of correlation between Vitrinite reflectance and Tmax is given in the chart.

Anomalous values of Tmax were found for organic mater associated with high uranium content due to local radiolysis.

Tmax is a good maturation index for type II and type III organic mater. In most cases, the oil window is attached for values around 435C

o. Except for type II-S for which it begins around

420Co.

The gas/condensate window is reached at 450Co for Type I organic matter, 455Co for Type II and 470C

o for Type III. The dry gas window is attained at 540C

o for Type III.

Tmax should be represented in a vertical log as a function of depth in order to visualize its slow increase with depth and to eliminate abnormal values.

Tmax is also a powerful tool to detect pollution by drilling fluids and natural impregnation of hydrocarbons, either migrating or trapped in a reservoir. In such cases Tmax is

abnormally low.

Hydrogen Index (HI)

Hydrogen index is an important calculated parameter that helps to define whether a sample is oil prone, mixed oil and gas prone.

Hydrogen index corresponds to the quantity of hydrocarbon generated relative to the total organic carbon (TOC). Hydrogen index is not computed if TOC is

26

HI = S2/TOC (expressed as mg HC/g TOC)

In the interpretation of hydrogen index data, following guidelines are used: HI = (S2/TOC) x 100

Gas prone sample is represented through the HI range from 0-200, mixed oil and gas through 200-300, and oil more than 300.

Oxygen index is defined as the ratio between S3 (expressed in mg CO2/g rock) and TOC (expressed as weight percent).

OI = S3/TOC (expressed as mgCO3/g TOC)

A good correlation was found between H/C of kerogen, measured after acid treatment of the rock matrix, and their hydrogen index measured by the Rock-Eval pyrolysis of the rock

sample.

This correlation exists for all types of organic matter and for all stages of thermal maturation, with the exception of, however, immature peats and lignites, which have a high

oxygen/carbon ratio.

For peats and lignites a large proportion of hydrogen is combined as hydroxyl group (OH). This hydrogen is latter transformed into water and does not participate in the genesis of oil.

Pyrolysis of kerogene and coal show a fair correlation between OI and O/C ratio, although some oxygen is lost as water and does not contribute in S3 peak.

Diagrams of HI vs OI are currently used (Fig. 10) for kerogene types evaluation instead of conventional Van Krevelen diagrams obtained on kerogenes isolated from their rock matrix

by acid treatment.

For each type of organic matter, an evolutionary pathway trajectory can be defined from the immature stage down to the sub-graphitic stage in which almost all hydrogen and oxygen

have been lost (Fig. 10).

It can be seen from the figure 10, that evolutionary pathways are almost vertical for Type I and Type II kerogenes for which only a small amount of oxygen is lost at the beginning of

the thermal evolution, while coals and type III kerogenes show a strong decarboxylation

before they are able to generate hydrocarbons.

Another evolution diagram can be drawn by comparing the evolution of the hydrogen index of

different kerogenes as a function of their thermal evolution assessed by their Tmax (Fig. 11). It

can be seen from the figure that for type I kerogene, the depletion of hydrogen is very rapid,

corresponding to a small range of Tmax. Almost only liquid hydrocarbons are generated, and if

they are expelled from the source rock, very little amount of gas is generated. For type III,

depletion of hydrocarbon is progressive.

Sample Collection

The quality of any geochemical interpretation as well as its significance is determined directly by the quality of the samples and the initial design of the sampling program.

Geochemical data may be obtained on numerous types of samples, including outcrop, cuttings, cores, seeps, produced oil and gases.

27

No single sample can effectively represent all of the geochemical attributes associated with a hydrocarbon source rock system. Significant differences have been observed in the level of

organic enrichment, hydrocarbon generation potential and organic matter type, as indicated

by Hydrogen Index, between individual samples. Such organic geochemical variations are

consistent with the variability in the lithofacies itself.

Because of both the stratigraphic and lateral variability, observed in source rocks, sampling programs need to incorporate both random sampling and channel (composite) sampling.

Channel sampling provides a more representative overview of the source potential of a formation or interval; however, the better source intervals may be effectively diluted.

The channel sampling approach is most appropriate when one is attempting to correlate an oil to a specific source because oils represent an integrated product.

From subsurface samples, source rock potential cannot be adequately assessed if the well has been drilled using an oil-based mud. The situation results in anomalously high

generation potentials because of hydrocarbon contamination.

Caving can also result in problems. Specially caving may result in the dilution of source rock intervals and at the same time an over-estimation of possible source rock thicknesses if

the caved material represents coaly intervals and an underestimation of the absolute level of

thermal maturity.

Unlike subsurface samples, outcrop sample quality may be highly variable due to weathering. Surface weathering tends to result in oxidation, which reduces a samples level

of organic enrichment, total generation potential and apparent oil-proneness. It may also

influence the observed level of thermal maturity (Fig. 12).

It is, therefore, important that the freshest samples be obtained for analysis.

When sampling oil and gas, every attempt should be made to obtain samples from discrete producing horizons. In fact in basins with multiple sources and multiple pay zones, the use

of combined fluids may result in a completely inaccurate interpretation of the samples

hydrocarbon generation and migration history.

KEROGE

Kerogens are chemical compounds that comprise segment of organic matter in sedimentary rocks, insoluble in the normal organic solvents because of their huge molecular weight

(more than 1,000). The soluble portion is known as bitumen.

Each kerogene molecule is unique because it is formed by the random combination of numerous monomers.

Kerogens are the precursors to hydrocarbons (fossil fuels) and are also the material that forms oil shale.

Maturity

28

In petroleum geology, the maturity of a rock is a measure of its state in terms of hydrocarbon generation.

Maturity is established using a combination of geochemical and basin modeling techniques.

Organic rich rocks (termed source rocks) will alter under increasing temperature such that the organic molecules slowly mature into hydrocarbons.

Source rocks are broadly categorized as immature (no hydrocarbon generation), sub-mature (limited hydrocarbon generation), mature (extensive hydrocarbon generation) and

overmature (most hydrocarbon have been generated).

The maturity of a source rock can also be used as an indicator of its hydrocarbon potential. For example, if a rock is sub-mature, then it has a much higher potential to generate further

hydrocarbons than the one that is overmature.

Aquatic and terrestrial organic matter, that is preserved in sediments, is converted to kerogene by biological and very low temperature processes termed diagenesis.

As sediments are more deeply buried, kerogene is converted into oil and gas by thermal processes, known as catagenesis. Under extreme thermal stress, organic matter is meta-

morphosed into methane and graphite by a process, called metagenesis.

Changes in physical and chemical properties of organic matter can be used to determine the degree of transformation that has taken place. This is important to petroleum geochemists

because it tells them whether or not oil and gas have been generated in the source rocks.

A large number of techniques have been developed to determine the degree of thermal evolution, or maturity, of organic matter in sedimentary rocks. These include gas

chromatography and biomarkers (gc/ms) analysis on the solvent extractable organic matter

(bitumen) and Rock-Eval pyrolysis, pyrolysis-gas chromatography and kerogene

microscopy on the insoluble organic matter (kerogene).

Bitumen maturity analysis is, however, often not reliable because of the ease with which hydrocarbon liquids can migrate and thereby contaminate the sample being analyzed. For

this reason, methods of measuring kerogene maturity provide the most reliable data.

Rock-Eval pyrolysis is the most common kerogene maturity screening technique used by the petroleum industry. When organic matter is heated upto a temperature of 550C

o, in the

absence of oxygen, it breaks down or pyrolyzes into hydrocarbons that can be detected by a

Rock-Eval pyrolyzer.

The temperature, at which the maximum rate of thermal degradation occurs, is called Tmax. Tmax temperatures range from 435C

o to 450C

o for source rocks in the oil generation zone.

These temperatures are considerably higher than natural oil generation temperatures (100-

130Co), but can be calibrated to natural generation processes.

Kerogene microscopy can measure the change in colour in transmitted light of organic matter as it matures. Colour changes from yellow to amber to brown and finally to black are

calibrated accurately to numerical colour scale, the most common of which is TAI

(Temperature Alteration Index). Oil is generated when organic matter becomes amber at a

TAI value of 2.

The most commonly used and accurate kerogene maturity technique is Vitrinite reflectance.

29

Vitrinite is a coal maceral whose reflectivity increases systematically with maturity and can be measured very accurately with reflecting light microscopy. Oil is generated between 0.6

and 1.0 Ro, which is the percent of incident light reflected when viewed with an oil

immersion objective.

Although Vitrinite reflectivity has nothing directly to do with oil generation, it can be calibrated accurately to oil and gas generation processes.

Kerogene maturity data can also be used to estimate the amount of section lost at unconformities, including the present land surface, the proximity to igneous intrusions, the

throw (vertical displacement) of faults, the provenance of sedimentary debris, the location of

present or past overpressured zones, and many other events of interest to geologists.

Maturity also can be measured by a host of other techniques, each of which has its unique strengths and weaknesses. It is always best to use several techniques to determine kerogene

or bitumen maturity and to use experienced laboratories familiar with many pitfalls that can

affect the analytical results.

A trap that is formed after a source rock became inactive for example will not contain oil or gas generated from that source rock even though geochemical data appear favourable.

Thermal maturity and hydrocarbon generation

Presence of a hydrocarbon source rock is insufficient to insure that hydrocarbon generation will occur. Organic-rich units must undergo a favourable burial/thermal history in order for

the kerogenes to be broken down into mobile phase.

Conversion from kerogene to bitumen, bitumen to oil and ultimately oil to gas is manifested by a series of physical and chemical changes in both the kerogene and bitumen phases.

The most commonly utilized indirect measure of thermal maturity is change in vitrinite reflectivity. Vitrinite reflectance increases with increasing thermal maturity (Fig. 13).

Mean vitrinite reflectance data, typically based on between 50 and 100 individual reflectivity measurements, are commonly plotted as a function of depth on semi-log paper

(Fig. 14).

A normal profile is typically linear, representing continuous sedimentation and permits the identification of the top and base of each individual hydrocarbon generation and

preservation zone.

Vitrinite reflectance profile, however, often deviates from this ideal linear character. There are several analytical and geologic reasons for such deviations.

Analytically, there may be problems with the identification of true vitrinite. For example, if solid bitumens are misidentified as vitrinite, the mean reflectance value would appear to be

anamalously low.

Another analytical complication may arise when there is an association of indigenous primary vitrinite population as well as more mature recycled vitrinite and/or less mature

vitrinite, that is associated with caved cuttings.

30

In addition to the above noted analytical and sample problems, there are some geologic causes too for nonlinearity in vitrinite reflectance profiles.

One such cause is the presence of intrusives in the stratigraphic section. The presence of these intrusives results in significant high levels of thermal maturity these effects are largely

localized and reflect contact metamorphism.

An offset and an apparent decrease in thermal maturity with depth may result as a consequence of thrust faulting.

One of the most commonly cited reasons for discontinuous and nonlinear vitrinite reflectance profiles is the presence of an unconformity. It has been suggested that the

displacement in the vitrinite reflectance profile can be used to estimate the amount of

missing section at the unconformity.

Another geologic cause of an offset in the reflectance profile is a marked change in lithologic character, which in turn is associated with large contrasts in thermal conductivity

within the sedimentary column. For example, coal is a poor conductor and thus allows a

build-up of excess heat in the lower portion of the well. It is this excess heat that results

in the elevated levels of thermal maturity.

Note: Although vitrinite is the most commonly used thermal maturity index, it is, however,

stratigraphically limited to post-Silurian units, because of absence of woody land plants

prior to the Devonian. In addition, vitrinite is generally lacking in sandstones and carbonate

rocks and when present is poorly preserved.

When vitrinite is absent or poorly preserved, other indirect measures of thermal maturity, such as TAI and colour changes in conodonts, are utilized.

Thermal alteration index (TAI) technique is based on colour changes of spores and pollen grains in transmitted light or changes fluorescence colour and intensity in reflected light.

Although considered somewhat less accurate and more variable, TAI may be estimated

using amorphous kerogene.

NOTE: All the above-mentioned various thermal maturation indices can be correlated with each other.

31

Source rock maturity summary

Immature Source Rocks: Tmax 465Co Type II

Tmax >540Co Type III

Oil Window: Ro = 0.65 to 1.3%

Tmax 440 to 450Co for Type I organic matter

Tmax 435 to 460Co for Type II organic matter

Tmax 420 to 460Co for Type IIS organic matter

Tmax 435 to 470Co for Type III organic matter

Gas and Condensate: 470Co to 540C

o Type III.

Dry gas: Ro >1.6% Tmax >540Co Type III.

Transformation ratio

Transformation ratio is the ratio of free hydrocarbon to total pyrolyzable hydrocarbon i.e. S1/S1 + S2.

Elevated transformation ratio values, associated with depressed Tmax values, are indicative of the presence of nonindigenous (contaminated) organic matter.

Preservation of organic matter

Initial oxygen solubility is important, because lower initial oxygen concentration are more easily depleted leading to higher levels of organic preservation.

Oxygen slubility decreases with increasing temperature and increasing salinity. Because of these relationships, warm saline waters have a greater potential to develop anoxic conditions

than cooler fresh waters. In fact, warm saline bottom waters have been used as one

explanation for the widespread development of the organic-rich Cretaceous sediments.

One can anticipate then that enhance levels of preservation would be favoured at low latitudes, where water temperatures are elevated and evaporation is greater then

precipitation.

Secondary oxidizers, such as, sulphate, may play a major role in organic matter degradation, particularly in evaporitic settings. For example, within solar Lake in Sinai, over 90% of the

organic matter produced is degraded through sulphate reduction. Thus, preservation would

be favoured in environments where sulphate concentration were minimized.

In addition to the presence of biologic and chemical oxidizing agents, which may influence both the quality and quantity of preserved organic matter, the time of exposure within the

water column, is a function of water depth and settling rate.

32

Within oxygenated basins the degree of preservation is inversely proportional to the water depth, i.e., there is decreased preservation efficiency with water depth. Thus the idea that

source quality also improves in a more basinal position is not always the case, and is

probably only valid if much of the water column is anoxic or dysaerobic.

Settling rate is a function of the relative densities of the particle and the media through which it is settling and the particle size. In general, in order to achieve settling rates

sufficient to preserve organic matter, within an oxygenated water column, the material must

be incorporated into pellets by various zooplankton.

HYDROCARBO MIGRATIO

It is rare that a hydrocarbon source rock also acts a reservoir. These rare exceptions are associated with fracture production from such units as the Austin Chalk (Texas), the Bakken

Shale (North Dakota) and the Monterey Formation (California).

The process through which hydrocarbons move from the source to the reservoir is termed migration.

Hydrocarbon migration can be viewed as a two-step process: (1) primary migration i.e., movement of hydrocarbons from the source rock into the carrier network, and (2) secondary

migration, i.e., redistribution of hydrocarbons within the basin.

Depending upon the geologic setting, hydrocarbon movement may be either dominated by lateral (bed parallel) or vertical components.

Bed parallel migration dominates in settings lacking major faults and diapiric provinces. It permits the collection of hydrocarbons over very large regions and allows for the presence

of significant quantities of hydrocarbons outside the limit of the generative basin.

In contrast, vertical movement of fluids dominate in highly faulted systems and systems with major diapiric activity. In such systems the hydrocarbons are usually restristed to the

areal extent of the generative portion of the basin, and there are numerous multiplay fields.

In the bed parallel case hydrocarbon flow, in the simplest terms, can be consider updip. The nature of the flow determines how effective the migration process is in collecting and

concentrating the hydrocarbons within a basin.

The hydrocarbons will be either focused (concentrated) or dispersed. Migration is focused when a large generative region has its hydrocarbons concentrated into a small region.

Focused migration typically occurs within a basin where a structural high is largely

surrounded by a generative basin. Such conditions increase the overall prospectiveness of a

region.

In contrast, where there is a small generative region charging a large portion of a basin, the flow is considered to be dispersive. Dispersive migration is common when generation takes

place in a structural low and prospective traps are positioned around the basin flanks. Under

these circumstances, although the quantity of the hydrocarbons generated may be quite high,

the volume of hydrocarbons, reaching any individual trap, is generally small. Such

conditions, therefore, decrease the overall prospectiveness of a region.

33

The migration patterns are based on structural considerations and will be modified by the character and continuity of the carrier system. Common carrier systems include porous

sands (sheets and lenses), fracture systems, bedding planes, partings and unconformities.

Hydrocarbon flow will be diverted to those regions, which offer the least resistance (i.e., the greatest porosity and permeability).

In the tertiary basins, where hydrocarbon generation has only recently occurred, hydrocarbon flow directions can commonly be established using the present structural

configuration.

In older Mesozoic and Paleozoic basins, where considerable time has passed since the hydrocarbon generation, the present structural configuration may not reflect the patterns of

hydrocarbon flow during active generation. In such situations, it is necessary to construct the

basins geometry during the time of generation.

Bed parallel migration distances are largely limited by lateral carrier continuity appears to be limited by structural considerations, e.g., in rift basins, maximum migration distances are on

the order of tens of miles; whereas, in foreland basins, migration distances may be on order

of hundreds of miles.

Migration is ultimately terminated when the buoyant force is incapable of pushing the petroleum column through the pore network. This usually involves a facies change (i.e.,

stratigraphic trap) or an increase in the amount of pore-filling cement (i.e., diagenetic trap).

The presence of disruptive faults and/or diapirs result in a shift from bed parallel to vertical migration. Such situations explain the many cases where reservoirs and sources are

disassociated. The vertical flow may actually occur through a permeable rubble zone

associated with these structural features.

The rate of migration is a function of several independent factors, including API gravity (buoyancy), in situ hydrocarbon viscosity, effective porosity and permeability and the dip of

the carrier system. Migration rate increases with increasing API gravity, porosity,

permeability and dip and decreases with increasing viscosity.

Therefore, the rate of hydrocarbon movement may play a role in foreland basins, where regional dips are low and migration distances may reach sever hundred miles. Rate does not

appear to be important in rift settings where migration distances are only on the order of

several tens of miles.

RESOURCE ASSESSMET

The ultimate aim of basin evaluation process is the estimation of the quantity of hydrocarbons available for entrapment.

The approach specifically addresses the estimation of oil-in-place, and does not address gas quantifications, which may introduce substantial errors into the calculation (e.g., gas

solubility, diffusion etc).

The amount of oil available for entrapment actually represents only a small percentage of the generative potential. The potential quantity of oil is reduced by the lack of generation

(level of thermal maturity), the retention of hydrocarbons by the source rock (expulsion

34

efficiency), the retention of hydrocarbons in the carrier network (residual hydrocarbons), the

loss of hydrocarbons from the system by breaching of a trap, the bypassing of a trap,

displacement of oil by gas, and the generation and migration of hydrocarbons prior to trap

development.

Ideally each of these components should be addressed individually; however, sufficient information for such an analysis is not presently available, even in the more mature

exploratory provinces.

It is, therefore, has been assumed that the amount of oil entrapped can be represented by a percentage of the oil-like (C15

+) hydrocarbons in the source system. This percentage is

termed the basins efficiency factor.

At the present time, the assignment of an efficiency factor is semiquantitative at best. Empirical data suggests the efficiency factors range from less than 1% in the Paris basin to

approximately 35% in the Los Angeles basin.

The quantity of hydrocarbons, present in the source rock system, can be estimated in either of three ways.

The first method is based on the direct measurement of C15+ hydrocarbons, within generative

basin. These values may be obtained either through extraction and gravimetric analysis or

through pyrolysis. If determined through pyrolysis, the S1 values can be equated to C15+

hydrocarbons.

ote: Unfortunately, samples of mature source rock, within the generative portion of the

basin, are usually not available and if available are not available in sufficient quantities or

with the necessary geographic distribution to be considered representative of the generative

basin.

The other two approaches utilize information from the immature portions of the basin to estimate the quantity of hydrocarbon present within the generative portion of the basin.

One of these approaches utilizes the empirical relationship between the level of thermal maturity (observed or calculated) and the transformation ratio, as defined by pyrolysis. This

method is limited to samples that have not matured beyond the oil-window. This method is

not appropriate for more elevated levels of thermal maturity, because the ratio does not take

into consideration either the gas or gasoline-range hydrocarbons which form as a result of

thermal digradation of heavier hydrocarbons.

The third approach estimates the amount of hydrocarbons through a kinetic model of hydrocarbon generation (Sweeney et al., 1987). This requires information on the burial and

thermal history of the source rock, the level of organic richness and the kinetic constants

associated with the source rock. More often, kinetic constants used in these calculations,

represent published values for the appropriate kerogene type rather than values obtained

for the specific source rock system under evaluation.

ote: It is important to note that variations in these parameters may have a significant

impact on the calculated volumes of hydrocarbons generated and the timing of generation

(Fig. 15).

35

Unlike the empirical correction for thermal maturity, the use of the kinetic model permits to estimate the amount of heavy liquids (i.e., petroleum) remaining even within the more

thermally mature portions of the basin. This is possible because these models take into

consideration the thermal degradation of oil into gas.

The volume of source rock is determined by defining the areal distribution of the generative basin and the net source rock thickness.

The net source rock thickness is used, rather than the gross source rock thickness, to account for the variability observed