The following describes the main methods used in petroleum exploration
1. SAMPLE PREPARATION 1.1 Introduction
Samples are received in the form of canned well-site cuttings, bagged
cuttings, cores, outcrop samples or crude oils. Each sample is examined
visually and described; contaminants such as drilling mud additives
and caved material are removed. The drilling mud is removed with cold
water, unless they are oil based: then the samples are washed in dichloromethane.
Once dried the rock samples are divided for optical and molecular analysis.
The optical fraction is ground to µm and the fraction for molecular
analysis ground to (<212µm). Condensates and crude oils are
separated into fractions by liquid chromatography or diluted as appropriate
prior to analysis. Headspace gases are analysed directly.
1.2 Kerogen preparation
Samples requiring kerogen analysis are finely ground as for optical
analysis, treated with excess hydrochloric acid to remove the carbonates
and finally treated with excess hydrofluoric acid (HF) to remove any
silicates. The kerogens are then washed, dried and mounted on a glass
slide for viewing in transmitted light for spore coloration (SC) and
kerogen type analysis.
1.3 Solvent extraction
Approximately 100 grams of finely ground rock (<212um) is refluxed
in a Soxhlet apparatus for 18 hours with an azeotropic mixture of dichloromethane/methanol
(93:7). Any elemental sulphur is removed by activated copper turnings.
The solvent and extract are then decanted and reduced to dryness by
means of a rotary evaporator. The total weight of the extract is recorded.
The separation of the samples into aliphatic and aromatic
hydrocarbons is achieved by liquid column chromatography (LC) or thin
layer chromatography (TLC) depending on how much sample material is
required. Liquid chromatography provides sufficient sample for several
analyses. The oil or extract sample is dried onto deactivated alumina
and placed on an alumina : silica column (1:3). The aliphatic hydrocarbon
fraction is eluted with pentane, whereas the aromatic hydrocarbon fraction
is firstly partially eluted with a pentane and 10% dichloromethane mixture,
then with a 20% dichloromethane pentane mixture. These resulting fractions
are stored for further analysis. When less sample material is required
TLC is used to separate the aliphatic from the aromatic hydrocarbons.
Pre-prepared silica gel plates are first conditioned, spotted with oil
or extract material and then developed in hexane. An accurate percentage
breakdown of the oil or extract into saturate and aromatic hydrocarbons,
resinous compounds and asphaltenic compounds (SARA) is achieved by the
Iatroscan method. The Iatroscan method uses automated combined TLC with
a flame ionisation detector (TLC/FID).
The asphaltenes may be collected by precipitation overnight in hexane.
The precipitate is filtered off, dried, weighed and stored for analysis.
2. MATURITY EVALUATION
Optical microscopy is the main technique used for maturity estimation
in solids. Three techniques are typically: Vitrinite reflectance (Ro%),
spore fluorescence (SF) and spore coloration (SC). Further maturity
evaluation techniques used include: Rock Eval pyrolysis and Tmax determination;
in both these source rock extracts maturity is assessed by examining
the n-alkane distributions, the biomarkers and the aromatic hydrocarbon
ratios by gas chromatography (GC) and gas chromatography-mass spectrometry
2.1 Vitrinite reflectance
The whole rock technique is preferred; however, when there is insufficient
suitable material on which to make the measurements isolated kerogen
mounts are also examined in reflected light. The crushed sample is mounted
in a liquid polystyrene resin, allowed to harden, ground on successively
finer carborundum paper, and then polished with successively finer alumina
powders. The samples are then viewed under reflected light using a (Leitz)
photometric microscope with reference to optical standards the samples
are viewed in white light using oil immersion objectives and a green
filter with a peak transmission of 546nm. The immersion oil has a refractive
index (Nt) of 1.518 at 23°C. The values are recorded as a percentage
of light reflected. Changes in reflectance values greater than Ro 0.1%
are thought to be significant. Typical standards used are: Yttrium aluminum
garnet (YAG) Ro% 0.921, and artificial sapphire Ro% 0.504.
Considerable operator skill is required to distinguish between autochthonous
and allochthonous vitrinitic components, other features such as degree
of bitumen staining, mineralogy, micropalaeontology and oxidation effects
arc also noted. Values of vitrinite reflectance with reference to the
oil and gas window may be seen in the figure entitled "correlation
title, molecular parameters". (Fig. 1).
Reflectance measurements are particularly reliable above Ro 0.5%; below
this value other parameters are used. In immature rocks, the reflectance
changes erratically with increasing maturity.
In lithologies subjected to recent rapid subsidence, in zones of oil
ingress and in horizons of intense reworking vitrinite reflectance values
may well be unreliable or even unavailable.
2.2 Spore fluorescence
The degree of sample fluorescence is determined by observing the excitation
colours when the sample is irradiated with UV light. This type of illumination
causes certain components e.g. spores, algae, plant waxes, cutinite
and oil, to fluoresce. The fluorescence colour observed depends on the
maceral type and maturity. It is therefore important that the determinations
are made on one maceral type. Spores have been found to be the most
reliable fur maturity assessments.
Table 1. Spore fluorescence scale
|3. Light range
|5. Dark orange
The correlations between the fluorescence colour number, the maturity
and the other maturity parameters are displayed in Fig. 1. The SF technique
is particularly useful for the maturity range Ro 0.3 to 1.0%. It can
be extended to levels of maturity up to 1.3%. Fluorescence observation
is also a useful tool to determine the extent and the amount of bitumen
2.3 Spore colour
This technique is extremely useful in the immature to early zone of
oil generation. The technique uses transmitted light microscopy. The
colour determination of suitable spores is made by eye with reference
to a standard set of spores. The spore colour index (SCI) value is obtained
by referring to the conversion able overleaf`:
Table 2. Spore colour conversion table
- pale yellow
yellow - lemon yellow
yellow - golden yellow
|9 0 Very
SCI increases with increasing maturity. Figure 2 shows
the correlation between SCI value, the oil window and other maturity
2.4 Pyrolysis (Rock Eval)
This screening technique. provides parameters which are both measures
of maturity and kerogen type. Tmax can be a useful indicator of maturity;
435°C ±10%: marks the transition from immature to mature
organic matter. Values in the range. 435 to 460°C ±10%: represents
the peak oil generation (the oil window). Values of 455 to 460°C
± 10% represent the transition from oil to wet gas generation.
The Hydrogen Index (HI, defined under source rock evaluation) is also
used as a maturity indicator. HI) will decrease with increasing maturity
as labile hydrogen-rich compounds leave the kerogen nucleus.
2.5 Gas chromatography (GC)
Analyses are undertaken using a gas chromatograph equipped with a data
station and integrator. The capillary column typically used is a 25m
x 0.15mm id. (narrow bore) fused silica column, wall-coated with 0.12mm
of a cross-bonded non-polar phase Silica. The oven temperature is held
at 500C for one minute, then raised to 320C° at 5°C-min The
n-alkane distribution may reveal the maturity of the precursor source
rock or be the result of subsequent alteration. Careful interpretation
will reveal which is the case.
2.6 Gas chromatography-mass spectrometry (GC-MS)
Mass spectrometry is used to identify characteristic
compounds found in oils and source extracts. It is a considerably more
powerful and specific technique than GC FID.
A typical GCMS set up may be a VG trio Quadrapole instrument coupled
to an HP 8150 GC. The instrument is operated in both the full scan (SCN)
and selected ion mode (SIR). The sample is introduced using an `On Column
Technique'. The column type is virtually the same as that used in the
Philips GC. However a slightly wider bore is needed to accommodate the
capillary syringe needle.
When the instrument is operated in SIR mode it is set to monitor ions
specific to certain classes of biomarkers. Both aliphatic and aromatic
hydrocarbons are monitored. At present the aliphatic groups are monitored:
triterpenoidal hydrocarbons (m/z 191, 123); steroidal hydrocarbons (m/z
217, 218, 231, 259 & 273); bicylics (m/z 123) are also monitored.
The aromatic fraction is monitored for the mono-aromatic steroidal hydrocarbons
(m/z 253), tri-aromatic steroidal hydrocarbons (m/z 231 and m/z 245),
phenan¬threnes (m/z 192 & 178), naphthalene and the methylated
naphthalene compounds (m/z 142, 156, 170, 184). Ratios are calculated
for certain components (eg. sterane 20S:20R), whose stereochemistry
depends on maturity; these ratios are normally calculated in the form
of product /(product + reactant).
3. SOURCE ROCK EVALUATION
3.1 Bulk techniques
3.1.1 TOTAL ORGANIC CARBON
Total organic carbon (TOC) is determined by treating a small aliquot
of the crushed sample with concentrated HCl to remove the carbonates.
The sample is washed with distilled water, dried and analysed in duplicate
in a LECO furnace.
The measurement provides a direct determination of the TOC present in
rock samples. In general, shales with TOC values below 1.0% wt. are
not considered prospective sources for generation of commercial quantities
of oil or gas.
The TOC values are interpreted follows:
Once the amount of organic carbon has been established it is then necessary
to determine the amount of hydrogen associated with the carbon. The
higher the hydrogen content relative to carbon the better the source
rock. This determination and other primary and derived values are determined
Pyrolysis data are obtained using the Rock Eval method. Analyses are
undertaken using the Rock Eval OSA method. A small amount (100mg) of
the crushed sample, selected on the above criteria, is weighed in a
crucible, placed in the furnace by an autosampler and progressively
heated. Initially the temperature is raised to 100oC and the volatile
hydrocarbons are driven off (peak SO). The temperature is then progressively
raised to 300°C. During this temperature ramp the heavier "free"
hydrocarbons arc driven off (Peak S2). The temperature is further increased
to 550°C. The higher temperatures result in the thermal degradation
of any organic matter (kerogen) contained within the rock. All the released
gases are detected by a flame ionisation detector (FlD). Peaks SO, S
1 and S2 are measured in mg HCg rock-1. The temperature at which the
kerogen breaks down most readily is referred to as Tmax. This value
is a useful indication of source rock maturity.
A guide to the interpretation of the S2 values and hence hydrocarbon
potential is given below:
From the primary data a number of derived parameters may be recorded.
The two most useful derived parameters are:
HI is a measure of the hydrocarbon generating potential of the kerogen
(see table 3).
PI when used in conjunction with other PI data from the well-bore is
a useful indicator of the amount of cracking the kerogen has undergone.
It is also useful to delineate zones of inward and outward migration.
Tmax, H1 and P1 are dependent on maturity and kerogen type. Tmax values
for immature kerogens are below 420oC± 10%. The perk oil window
lies between 435 and 445°C. The late zone of oil generation and
peak zone of condensate generation occurs between 445 and 455oC. Above
455°C only condensate and gas can be expected. With increasing maturity
any generated gases will become progressively drier. It is thought that
no further generation is possible beyond a Tmax of 500oC; this is the
maturity equivalent of a vitrinite reflectance of approximately Ro 3.0%.
HI values will decrease with increasing maturity; the exact values will
depend very much on the starting values. As an example H1 values above
550 would indicate an immature highly aliphatic oil-prone kerogen. Values
below 200 may indicate an immature non-aliphatic kerogen or a fully
mature formerly hydrogen-rich kerogen. See Fig.2.
3.2 Kerogen type
Optical techniques, microscopy
During the measurement of maturity by all methods,
a note is also made of the amount and types of the various kerogen types.
A classification using our broad kerogen types is used: (Types I, II,
III and IV). Sec also the Van Krevelan diagram, Fig.2.
Samples containing sufficient Type I or II kerogens have the potential
to generate oil; under increased thermal stress gas will be generated.
Type III kerogens mainly generate gas with only ii small amount of oil,
whereas Type IV have little or no potential to generate anything.
The Type of kerogen present in sample also provides some indication
of the environment of deposition in which the rock was deposited. For
example algae, Type I kerogen, may indicate either a lacustrine (e.g.
Botryococcus or a marine environment (e.g. Tasmanites). Type II kerogens
are largely confined marine shelfal environments. Type Ill kerogens
are derived From continental organic material but the organic matter
can be transported beyond paralic swamps well into the marine environment
(duplex source). Primary inertinite, type IV kerogens, and of continental,
origin can also be transported to a variety of environments. The presence
of inertinite dilutes the source rock's potential (the active carbon
is reduced). All four kerogen types are just convenient end members
in a continuum. Determining the HI will give a bulk determination of
oil or gas potential, but HI values are less useful for a palaeoenvironmental
examination, to establish environments of deposition completely a combined
organic petrological-paly¬nological approach is used.
Kerogen typing is also used to help determine maturity. Organic matter
becomes progressively darker with increasing maturity: the degree of
darkness, the Thermal Alteration Index (TAI) has been given an ascending
series of values from approximately 2 to 4. In this study values of
TAI derived from Service Company reports were converted to Ro% using
Table 4 (Warples 1980).
3.3 Molecular techniques and interpretation
Gas chromatography (GC), Gas chromatography-mass spectrometry
(GC-MS), prior to undertaking any GC or GC-MS analyses a standard oil
is analysed to ensure consistency and highlight any possible problems,
n-Alkane distributions, biomarker and other compound profiles derived
from the analysis from solvent extracts can also provide useful information
on kerogen type and depositional environment for the source rocks; this
approach is used to examine the oils in detail to gain further information
about presumed source rocks.
The type of data may include:
The position of the n-alkane maxima and distribution of the n-alkanes
may indicate whether marine (C15 - C20) or terrestrial (C27 - C33) organism
have contributed to the kerogens.
The relative amounts of pristane (Pr) to phytane (Py) are thought likely
to indicate redox conditions that existed when the sediments were deposited.
There are many other useful parameters: in addition, the presence of
other compounds such as iso¬prenoids and unresolved material are
Biomarker profiles derived from GC-MS analyses also contain valuable
data which can give clues as to the origin of the sediment. For example
the ratio C27 : C28 : C29 steranes have been used extensively to differentiate
between marine and terrestrial input recent research has thrown some
doubt on the usefulness of this ratio and many others. In practice the
interpretation of these ratios is only undertaken with caution and in
conjunction with all other available data.
A table of GCMS derived parameters and characteristic ions normally
used is included in the appendix (see tables 5 and 6).
Prior to any GCMS or GC run a standard oil is analysed to check the
instrumentation. For the North Sumatran work a Tertiary oil from central
Sumatra was used for GCMS work and the Villeperdue oil from the Paris
basin for the GC work. (see Figs. 3 GC n- and iso-alkanes, GCMS aliphatic
hydrocarbons, triterpanoids and GCMS aromatic hydrocarbons, steroidal
4. CORRELATION, ALTERATION & MIGRATION
GC and GCMS and isotope techniques are also used in
correlative, migration and oil alteration studies. The analysis of the
stable isotopes of carbon, hydrogen, sulphur and, to a lesser extent,
nitrogen can he particularly useful in correlative, maturity, palaeoenvironmental,
oil alteration and migration studies. The data are used in conjunction
with other geochemical parameters. In this study only carbon isotopes
were used to help reconstruct the palaeoenvironment. Fig. 7 explains
the units used, Fig. 8 shows the range of 13C‰ values that occur
in nature and Fig. 9 describes the stable carbon isotopic changes that
occur in kerogens and breakdown products.
4.1.1 CORRELATION STUDIES
Using the molecular and isotopic techniques possible oil, gas and source
rock correlations may be investigated. The same data may also be used
in migration studies.
4.2 Alteration studies
Once reservoired or during migration, oil may be altered and the original
characteristics lost. The principle modes of alteration arc: biodegradation,
waterwashing, asphaltene precipitation, UV alteration and evaporation.
In all processes expect asphaltene precipitation the resulting oil becomes
heavier and more viscous.
This also includes enzymic alteration. Biodegradation will only occur
below a maximum temperature of 80°C. Additionally a supply of waterbourne
nutrients is required. Biodegradation often follows a set path, with
the more readily digestible compounds being selectively removed first.
To establish the extent of biodegradation in mature oils a scheme has
been adopted from Alexander et al. 1983, see Table 7.
The more water-soluble components of oil are removed sequentially by
either ground water or formation waters. Generally water-washing and
biodegradation occur simultaneously.
4.2.3 ASPHALTENE PRECIPITATION
This is an in-reservoir phenomenon only, Gas or low molecular weight
hydrocarbons injected into a reservoir of oil will cause asphaltenic
compounds to precipitate out from the oil and fall to the bottom of
the oil column. In-reservoir gravity separation will also have this
Long migration paths may result in heavier molecules or asphaltenic
complexes being preferentially held back.
4.2.4 UV ALTERATION
This is exclusively a surface phenomenon Therefore it will be encountered
only at oil seeps and in surface pools of oil. UV irradiation causes
photochemical destruction of many hydrocarbon species.
Again this is exclusively a surface effect. The lighter more volatile
hydrocarbons will be preferentially lost; this process is termed impissation.