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14 THE PETROLEUM PLAY
14.1 Introduction
A petroleum play a model of how the interplay between a number of geological
factors might result in the formation of a petroleum accumulation at a specific
stratigraphic level within a basin. The important geological factors are:
1. A petroleum charge system comprising thermally mature petroleum source rocks
capableof expelling petroleum into porous and permeable carrier beds, which
allow it to migrate towards sites of accumulation.
2. A reservoir unit capable of storing the petroleum and yielding it to the well bore at
commercial rates.
3. Petroleum traps which concentrate the petroleum in specific locations, allowing
exploitation.
4. A regional topseal or caprock to the reservoir unit which contains the petroleum
at the stratigraphic level of the reservoir.
5. The correct relative timing of the above four elements, so that, for example,
suitable reservoir units and traps are available at the time of petroleum migration.
A play is thus a group of discovered pools of petroleum and undrilled prospects that
are believed to share a common petroleum charge system, gross reservoir and
regional topseal.
The geographical area over which a play is considered to extend is termed the play
fairway.
The extent of a fairway is initially determined by the depositional or erosional limits of
the gross reservoir unit but may also be limited by the known absence of any of the
other factors. A play fairway may be mapped out in the form of a play map.
A play is considered as proven if petroleum accumulations are known to have
formed by the operation of the geological factors that define the play. In other words,
the necessary combination of geological conditions is known to be present in the
area and the play may be said to be working. An unproven play is one in which
there is some doubt as to whether the geological factors actually do combine to
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produce a petroleum accumulation. One of the objectives of play assessment is to
estimate the probability of a play working. This is known as play chance.
14.2 Basin Analysis
Basin analysis is the starting point for assessing the undiscovered petroleum
potential of an area. Assessments of this type guide exploration programmes.
Rational and realistic predictions of source rocks, reservoir rocks, topseals and traps
require valid geological models. This requires the correct interpretation of:
1. The fundamental tectonic and thermal processes controlling basin formation and
evolution.
2. The geometry and sedimentary facies of the stratigraphic succession within the
basin (sequence stratigraphy).
The overall location and form of major depositional sequences can be interpreted in
terms of the mechanical processes of basin formation, which are governed in turn by
the behaviour of the underlying lithosphere. Consequently, basins produced by
lithospheric stretching, flexure or strike-slip deformation will exhibit different
characteristic locations, geometries and evolutions. It is possible to recognise
packages of depositional sequences (variously termed megasequences or
supersequences) that are related to different phases of basin formation and
evolution. These packages are bounded by major regional unconformities that mark
the onset and end of a major basin-forming event. For example, a rift basin
megasequence deposited during a period of lithospheric stretching may be overlain
by a passive-margin post-rift megasequence formed during the subsequent thermal
subsidence phase. The underlying mechanism of basin formation also indicates a
particular tectonic and thermal regime in the basin. This information is important in
modelling potential source rock intervals.
The first step in building geological models for play assessment is the identification
and interpretation of the megasequences present in a basin. The stratigraphic
succession contained within each megasequence is controlled by the interplay of
tectonic subsidence, sedimentation rate and sea level changes. Each
megasequence comprises a series of depositional sequences and systems tracts
representing discrete phases of the basin infill. The analysis of these depositional
sequences forms the basis for the prediction of source, reservoir and caprock.
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The aim of basin analysis is to obtain a reliable chronostratigraphic interpretation of a
succession, so that the distribution and nature of the sedimentary facies can be
understood in terms of geological processes operating through time. The
chronostratigraphic interpretation will be constructed from the interpretations of
lithostratigraphy, biostratigraphy and seismic stratigraphy. The accuracy of the
interpretation will depend upon the type, amount and quality of the available data.
Deficiencies in the database usually mean that more than one interpretation fits the
observable information. As a result, each geological model constructed from the data
will inevitably carry an associated risk of being invalid. This is termed model-risk.
Model risk has to be incorporated into play assessment (see section 14.7.4).
The chronostratigraphic diagram is a useful method of presenting the relationships
between sedimentary facies in a sequence (fig. 84). Combined with a sequence
isopach map, the chronostratigraphic diagram can be used to make sedimentary
facies predictions for the entire stratigraphic succession.
Once the sedimentary facies have been determined, the next step is to make
predictions of potential source, reservoir and caprocks. At this stage, the thermal
maturity of the source rock and the presence and timing of traps should also been
determined. At this stage, there is a risk that, while the geological model is valid,
these elements of the petroleum play may be absent. This a additional element of
risk is termed conditional play risk (see section 14.7.4).
The next step in play assessment is to produce a suite of maps showing the
distribution of potential source, reservoir and caprock facies. Note that:
1. The sources and caprocks may be outside the depositional sequence containing
the reservoir.
2. A single source rock may charge a number of reservoir-defined plays.
3. A single reservoir-defined play may be charged from a variety of separate source
rocks.The objective of play assessment is to anticipate as far as possible all the
possible permutations of sources, reservoirs and caprocks that may produce
petroleum plays in the basin. For each reservoir-defined play, a single map may
be constructed to show the distribution of the potential reservoir facies, the source
“kitchen(s)” needed to charge the reservoir and the potential caprock facies.
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The final step in play assessment is the evaluation of individual traps in the fairway.
Figure 84. Schematic chronostratigraphic diagram. The chronostratigraphic diagram is a very useful method of showing the relationships between sedimentary facies in a sequence and the overall development of the basin. 14.3 The Petroleum Charge System
The petroleum charge system consists of two elements:
1. Thermally mature petroleum source rocks capable of expelling petroleum.
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2. Porous and permeable carrier beds which allow migration of the expelled
petroleum to the reservoir(s).
The distribution and type of petroleum source rocks is space and time can be
predicted from an understanding of their origin. The ideal conditions for source rock
deposition are:
1. Anoxic conditions beneath a region of very high organic productivity.
2. Shallow water depths.
3. Fine-grained sediments.
There are three main depositional settings where such conditions can occur:
1. Lakes.
2. Deltas.
3. Marine environments such as barred basins or open shelves where there is an
oxygen minimum layer.
Geochemical evidence can be used to determine the presence, richness (Total
Organic Carbon and pyrolysis yield) and stage of maturity (vitrinite reflectance, spore
colouration, etc.) of a source rock. More sophisticated geochemical techniques, such
as gas chromatography and isotope studies, can be used to determine the probable
petroleum products and correlate source rocks with oils in reservoirs. Source rocks
can be classified into three types on the basis of their initial kerogen concentration
and kerogen type, parameters that determine the timing and composition of the
petroleum expelled (fig. 85):
1. Class 1 source rocks have predominantly labile kerogen at concentrations of >10
kg ton-1. Generation starts at about 100°C and the kerogen generates an oil-rich
fluid. The source rock rapidly becomes saturated with fluid. Between 120 and
150°C, 60 to 90% of the petroleum is expelled as oil with dissolved gas. The
remaining fluid is cracked to gas at higher temperatures and expelled as a gas
phase.
2. Class 2 source rocks are a leaner version of Class 1, with initial kerogen
concentrations of <5 kg ton-1. Expulsion is very inefficient up to 150°C because
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insufficient oil-rich petroleum is generated. Petroleum is mainly expelled as gas-
condensate formed by cracking above 150°C, followed by some dry gas.
Figure 85. Petroleum Generation Index (PGI) and Petroleum Expulsion Efficiency (PEE) as a
function of maximum temperature for three classes of source rock. Principal petroleum phases expelled over relevant temperature ranges are shown. Curves were constructed assuming a mean heating rate of 5°C Ma-1. PGI is the fraction of petroleum-prone organic matter that has been transformed into petroleum. PEE is the fraction of petroleum fluids generated in the source rock that have been expelled.
3. Class 3 source rocks contain mostly refractory kerogen. Generation and
expulsion takes place only above 150°C and the petroleum is relatively dry gas.
Migration concentrates subsurface petroleum into specific sites (traps) where it may
be extracted. The main difference between primary migration (out of the source
rock|) and secondary migration (through the carrier bed) is the porosity, permeability
and pore size distribution of the rock through which migration occurs, these
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parameters being much higher for carrier beds. The main driving forces behind
secondary migration are buoyancy, caused by the density difference between oil or
gas) and the pore waters of carrier beds, and pore pressure gradients which attempt
to move all pore fluids (both water and petroleum) to areas of lower pressure. The
main restricting force to secondary migration is capillary pressure, which increases
as pore sizes become smaller. During secondary migration, petroleum flows in
discrete masses through the interconnected network of the largest pores in the
carrier bed; i.e. it does not sweep through the whole volume of rock
Secondary migration ceases when a smaller pore system is encountered whose
capillary pressure exceeds the driving forces of the petroleum. This pore system
constitutes a seal. If the original mass of petroleum is joined by further masses, the
increased volume of petroleum may possess a large enough buoyancy to cause
invasion of the finer pore network and the seal will thus leak. It is possible to
calculate the maximum petroleum column height that can be supported by a seal.
The end points of secondary migration are the trap(s) or seepage at the surface. If a
trap is disrupted at some time, its accumulated petroleum may migrate either into
other traps or leaks to the surface. The mechanism of such remigration is exactly the
same as that of the original secondary migration into the trap.
An understanding of the mechanics of secondary migration is necessary for the
following purposes:
1. In tracing and predicting migration pathways, and hence in defining those areas
this are receiving a petroleum charge.
2. In interpreting the significance of subsurface petroleum shows and surface
seepages.
3. To estimate the seal capacity in both structural and stratigraphic traps.
Since the driving force for secondary migration is buoyancy, petroleum will tend to
move in a homogeneous carrier bed in the direction with the steepest slope; i.e. in
the direction of true dip. Thus, structure contour maps can be used to model
migration pathways. During long-distance migration, as occurs in some foreland
basins, petroleum flow may be focused along regional highs.
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The style of migration drainage is divided according to whether migration is
principally lateral or vertical. However, it should be noted that the migration style can
vary in time and space within the history of a basin. Accurate estimates of the
distance from the “hydrocarbon kitchen” to the trap is an essential part of basin
modelling. However, the lateral distance to which petroleum can migrate is a difficult
parameter to measure. Traditionally, it has been done by simply measuring the
distance between the petroleum accumulation and the nearest mature source rock.
Correlation between source rock and reservoir oil using geochemical fingerprinting
clearly helps in accurately determining migration distances.
The are inevitably losses of petroleum during secondary migration. These losses
occur in two settings:
1. In miniature traps, too small to be of commercial interest.
2. As residual petroleum saturation in the pores of the carrier rock.
It is, however, difficult to quantify these losses.
Petroleum may also be physically and chemically altered while it is in the trap. Such
changes are brought about by bacterial action (biodegradation), removal of soluble
hydrocarbons by meteoric waters (water washing), precipitation of heavy
asphaltenes (deasphalting) and thermal alteration. These changes may have a
significant impact on the recoverable fraction and commercial value of an oil
accumulation.
14.4 The Reservoir
The primary considerations in the assessment of reservoir potential are the likely
reservoir porosity and permeability - the “plumbing” of the reservoir. Calculations of
reservoir porosity and qualitative indications of permeability can be obtained from
interpretation of wireline logs and can be directly measured with core material.
Porosity and permeability are influenced by:
1. The depositional pore-geometries of the reservoir sediment. Sandstone
reservoirs have a depositional porosity and permeability that is dependent on the
by grain size, sorting and packing of the clasts. It is important to realise that
porosity and permeability are not directly or simply related. Complex pore
geometries, for example, will present highly tortuous paths for the passage of
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fluids. This will significantly lower permeability but porosity will be largely
unaffected. Particular pore-filling minerals may have different effects on porosity
and permeability, affecting one but not the other.
2. The post-depositional diagenetic changes that have taken place. Diagenetic
changes are very important. In sandstone reservoirs, they would include
fracturing, recrystallisation, cementation and the crystallisation of clay minerals in
the pore spaces. Diagenesis invariably has a detrimental effect on reservoir
porosity and permeability.
Reservoirs are likely to be heterogeneous on a number of scales from the large
scale heterogeneities of stratigraphic packages down to the microscopic grain scale.
This heterogeneity is due to the architecture of the stratigraphic succession,
compaction, deformation, cementation and the nature of the pore-filling fluids. Large
scale heterogeneities of well-spacing size can usually be analysed on the basis of
detailed well log correlations and by use of sedimentological models derived from
cores. For smaller scale heterogeneities, cores are essential, since they provide
information on bed thickness, style of cross-stratification, grain size and microscopic
features. However, even cores will not necessarily give the complete story. The
correct identification of the depositional environment of the sediment and the use of
outcrop analogues greatly helps the assessment of heterogeneity. A knowledge of
reservoir heterogeneity is essential for the efficient exploitation of a hydrocarbon
reserve and therefore is the mainly the concern of the development geologist rather
than the basin analyst.
The tectonic setting of a basin may determine the composition of clastic reservoirs
and therefore their quality. The evaluation of tectonic setting is based on provenance
studies (petrography of outcrop specimens, core samples or drill cuttings). If basin
analysis indicates the likely tectonic make-up of a basin, the composition and
geometry of reservoir units can be estimated in very general terms using a
knowledge of the hinterland geology and sediment dispersal systems.
A petroleum play is initially defined by the depositional or erosional limit of its gross
reservoir unit. A reservoir rock must be porous enough to constitute a “tank” of
petroleum within the trap and its pores must be sufficiently interconnected to allow
the contained petroleum to flow through the rock to the well. Thus, the likely porosity
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and permeability of a reservoir are primary considerations in the assessment of its
reservoir potential. Reservoir porosity affects the reserve of a prospect. Reservoir
permeability affects the rate at which petroleum fluids may be drawn off from the
reservoir during production. Both of these parameters will have a major impact on
the commercial attractiveness of a play.
Reservoir rocks may result from a very wide range of depositional environments.
Depositional systems and facies models have clear implications for the occurrence
of reservoir rocks. In new areas, reservoir prediction will be difficult. Careful
sequence-by-sequence interpretations of sedimentary facies, using available local
data from outcrop and wells, integrated into a depositional model, and calibrated
against analogous sequences elsewhere, is the standard approach to reservoir
prediction. As more data becomes available, the models can be refined.
14.5 The Regional Topseal
An effective regional caprock or topseal is one of the essential ingredients of a
petroleum play. The nature of the caprock not only determines the efficiency of the
subsurface trapping system but also influences the migration routes taken by
petroleum fluids after leaving the source rock. The continuity of the regional topseal
largely determines whether the basin has a laterally- or vertically focused migration
system.
The basic physical principles governing the effectiveness of petroleum caprocks are
the same as those that control secondary migration of petroleum; i.e. a caprock is
effective if its capillary pressure exceeds the upward buoyancy pressure exerted by
an underlying petroleum column. The capillary pressure of a caprock is governed
mainly by its pore size and this may be very variable laterally. The buoyancy
pressure is determined by the density of the hydrocarbons and the hydrocarbon
column height.
The effectiveness of caprocks can be examined in terms of the following factors:
1. Lithology. Caprocks need small pore sizes, so the majority of caprocks are
fine-grained clastics (clays, shales), evaporites (anhydrite, gypsum, halite) and
organic-rich rocks.
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2. Ductility is also an important requirement, especially in tectonically disturbed
areas. Ductile lithologies are less prone to faulting and fracturing than brittle
rocks. Salt and anhydrite are the most ductile lithologies. Organic-rich shales are
also ductile and so many source rocks also serve as seals.
3. Thickness. To be effective, caprocks do not have to be thick.
4. Lateral continuity. To provide good regional seals, caprocks need to maintain
stable lithological character and thickness over broad areas. The lateral continuity
of the regional seal can be studied using wireline log information and seismic
stratigraphic analysis. Most important petroleum provinces have at least one
regional seal and the search for petroleum in such areas may be focused on the
base of the seal rather than on any particular reservoir horizon.
5. Burial depth is not critical.
The conditions required for the development of regionally extensive effective
caprocks in association with reservoir rocks occur frequently in two particular
depositional settings:
1. Where marine shales transgress over gently dipping clastic shelves; i.e. in
sequence stratigraphic terms, the transgressive systems tract extending from
the time at which the shelf begins to be onlapped to the time of sea level
highstand.
2. Where evaporites in regressive sabkhas regress over shallow marine
carbonate reservoirs.
14.6 The Trap
The final requirement for the operation of an effective petroleum play is the presence
of traps within the play fairway. A trap represents the location of a subsurface
obstacle to the migration of petroleum towards the surface. In a trap, the subsurface
conditions cause the concentration and accumulation of petroleum. The same basic
principles apply to trapping as to secondary migration and seals. A trap is formed
where the capillary displacement pressure of a seal exceeds the upward-directed
buoyancy pressure of petroleum in the adjoining porous and permeable reservoir
rock.
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The oil and gas exploration has been dominated by the hunt for specific geometries
that are diagnostic of the presence of a trap. As exploration techniques have
improved, the trap geometries sought have shifted from the large and obvious to
those that are more subtle and difficult to locate, particularly stratigraphic traps.
An understanding of the mechanism of trap formation and therefore the timing of trap
formation is essential to prospect evaluation. The trap geometry must be present
prior to the petroleum charge in order to trap petroleum. Each of the structural,
stratigraphic and hydrodynamic trap types has implications for trap timing.
Depositional and unconformity traps are very early, dating from the time the sealing
units became effective. Thus, these traps are ready to receive a charge from a very
early stage. Some structural traps, however, are very late in relation to petroleum
charge. Each trap needs to be individually evaluated.
14.7 Play Assessment
14.7.1 Introduction
Exploration companies require quantitative estimates of the undiscovered potential
of petroleum plays so that they can evaluate investment opportunities and develop
long term strategic plans. A range of techniques has been developed to estimate
undiscovered petroleum resources. They can be grouped into four categories:
1. Subjective methods, relying on the personal experience and ability of the
assessor. Such estimates can be highly biased.
2. Basin statistics consist of the historic field sizes and drilling success ratios for
a play. They provide a means of calibrating volume and risk estimates against
the reality of past experience. Basin statistics can be derived from within the
same play as the one being assessed or can be “borrowed” from an analogue
play elsewhere.
3. Statistical modelling of historical discovery data. Statistical “discovery process
models” that identify the process by which previous oil and gas discoveries
have been made, are applied to predict undiscovered field sizes. The models
require statistical data on the sizes and timing of previous discoveries.
Geological expertise is needed to define the play.
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4. Geochemical modelling uses the physical and chemical principles of
petroleum generation, migration and entrapment to calculate the volumes
generated, expelled, lost and available to charge traps. The approach is
limited because of the uncertainties surrounding volumes lost during migration
and as a result of leakage from traps.
In practice, these techniques are combined together in play assessment, which is
based upon the geological interpretations of depositional sequences made by means
of basin analysis.
Play assessment is carried out in four stages:
1. Definition and mapping of the play fairway.
2. Estimation of the numbers and sizes of undiscovered fields.
3. Estimation of play fairway risks
4. Calculations of undiscovered potential and calibration with charge volumes.
14.7.2 Definition and mapping of the play fairway
The first phase in play assessment is the definition of the play and the mapping out
of its fairway. Play fairway maps show the geographical distribution of the key
geological controls on the play. These geological controls are those that determine:
1. The presence of an effective reservoir.
2. A petroleum charge to the reservoir.
3. A regional topseal to the reservoir.
4. The presence of traps.
5. The right chronological development of the above factors.
Play fairways are primarily reservoir-defined. Hence, fairways at different
stratigraphic levels in a basin may be stacked vertically. Within a single play, all
prospects and discovered fields share a common geological mechanism for
petroleum occurrence. Petroleum accumulations, discovered or undiscovered, within
a single play fairway, can be considered to belong to a single population of
geological phenomena. Thus, each play will possess a specific distribution of field
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sizes. In addition, the drilling success ratio within a play may also be a characteristic
feature. The play assessment method is based on these assumptions.
Because of the heterogeneities in the geology over the extent of a fairway, it is
normal for play chance to vary areally. This variation in play chance might be due to
hard evidence of adverse geology in different parts of the fairway (e.g. determined
from wireline or seismic data) or it may be due to variations in the quantity or quality
of the data base. Consequently, an unproven fairway may be subdivided into a
number of common-risk segments defined by lateral variations in play chance. The
fairway can also be subdivided into segments if the anticipated field sizes (due for
example to differing structural development in different parts of the fairway) or drilling
success ratios are likely to vary significantly.
The drilling success ratio is the ration of the number of technical successes to the
number of valid tests of the fairway. A technical success is an exploration well that
flows petroleum to the surface or in which the presence of petroleum in drill-stem or
wireline formation test convincingly demonstrates the presence of a pool of
recoverable petroleum. Note that it carries no implication of commerciality. A valid
test is a well that penetrated the play fairway and is intended to test an exploration
target in the play fairway. There are normally far more dry holes than technical
successes in a play. Within a proven play, dry holes are caused by local geological
variations, such as the absence of a lateral seal in a faulted prospect or the local
diagenetic destruction of reservoir porosity.
14.7.3 Estimation of the numbers and sizes of undiscovered fields
The second stage in the assessment is the estimation of the number and sizes of
undiscovered fields in each common-risk segment.
The estimation of field sizes can be carried out in a number of ways and its accuracy
will be determined by the quantity and quality of the available data. The options
include:
1. Using existing field size frequency distribution for the play as a guide to future
field sizes.
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2. “Borrowing” a field size frequency distribution from an analogue play. If field
sizes are “borrowed” from an analogous play, care must be taken that the
analogue is truly valid.
3. Computer modelling based on trap area, porosity, etc.
Ranges of possible field sizes must be consistent with the sizes of already identified
prospects in the segment and be calibrated against already discovered field sizes in
the same or an analogous play.
The determination of prospect volumes involves two calculations:
1. Trap volume. A rough estimate of reserves prior to drilling can be calculated
as follows:
R = Vb x F
Where R = recoverable oil reserves.
Vb =bulk volume of trap calculated from the area and thickness of
the trap estimated from seismic data.
F =recoverable oil; i.e. the fraction of the in-place petroleum
expected to be recovered to surface.
The recoverable oil is the most difficult figure to assess unless local
information is available from adjacent fields. This formula assumes that the
trap is full to its spill point. Once a field has been discovered, accurate data
becomes available and more sophisticated formulae can be applied.
However, the recovery factor remains hard to estimate.
2. Charge volume. The calculation of trap volume only determines the trap
capacity. If the charge is inadequate, the trap will not be full. In these
circumstances the trap volume will need to be modified by a degree of fill
factor (DOF) or the charge volumes from geochemical modelling used
directly as the limiting petroleum volume for the prospect. Calculation of the
latter is difficult because some of the parameters required, especially the
volume lost during migration, are difficult to estimate. Consequently, charge
volumes are subject to large errors.
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The number of undiscovered fields in a play can be estimated in a number of ways:
1. By counting the number of identified and notional prospects greater that the
minimum size on the field size distribution and dividing by an anticipated
drilling success ratio (which may be “borrowed” from an analogue).
2. By “borrowing” a prospect density (number of prospects per unit area) from an
analogue, scaling the number of prospects in the area of the play and dividing
by the drilling success ratio.
3. By directly “borrowing” a field density from an analogue play. This avoids the
need to count prospects (which may be impossible or impractical) or to
estimate drilling success ratio. The number of undiscovered fields can be
plotted as a probability distribution, although it is frequently adequate to make
a single-point estimate.
The sum of all the predicted fields is an estimate of the undiscovered potential of the
play.
14.7.4 Estimation of play fairway risks
The third stage involves assessment of risk. There are three elements of risk in play
fairway analysis, which are an outcome of the process of conceiving a play. These
are:
1. Model risk Play chance
2. Conditional play risk
3. Prospect-specific risk.
Model risk is the chance that the interpreted geological model for the fairway is
valid; specifically the geometry and sedimentary facies of the depositional
sequences involved in the play. Model risk is largely a function of the adequacy of
the data types (outcrop, wells, seismic) in constraining the stratigraphic
interpretation.
If the model is considered valid, conditional play risk is the chance that an effective
play is produced; specifically a timely petroleum charge into a producible reservoir
with an effective regional topseal.
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Model risk and conditional play risk together constitute the absolute risk on a play
being present. This is known as play chance. A play chance estimate is built up by
considering the charge, reservoir, topseal and trap elements of the play. It relates to
the chance that these elements will combine somewhere in the fairway to produce
the required number and size of fields. If an element of the geological model or
conditional play is absent, the entire play is invalidated. Play chance can be
calibrated with worldwide statistics on the success rates of plays in various parts of
the depositional sequence. On this basis, sandstone plays in transgressive systems
tracts and carbonate plays in highstand systems tracts are the most successful.
Prospect-specific risk is specific to individual prospects. It relates mainly to the
presence and effectiveness of the trap, although there may also be prospect-specific
risks on the prospect charge system or reservoir. Prospect-specific risk exists even
in a proven play and is caused mainly by unpredictable heterogeneities in geology
over the extent of the fairway. Simple stratigraphy and tectonic style will generally
allow a very good drilling success ratio, perhaps as good as 1 in 2. In contrast,
extremely variable stratigraphy combined with a complex tectonic history will
generally give a very poor success ration, perhaps worse than 1 in 10. Prospect-
specific risks can be calibrated by drilling success ratios in proven analogous plays.
Obviously, two factors affect prospect-specific risk:
1. The quantity and quality of the available geological data. In general, a poor
data base tends to result in inaccurate geological interpretation of the
prospect.
2. Exploration maturity often improves drilling success ratios. However, in very
mature plays of finite size, a point is reached where the success ratio begins
to decline as it becomes harder to find economically viable fields.
The chance of success in an individual prospect, prospect success chance, is the
product of each of these three elements of risk and is the probability of encountering
petroleum volumes in the prospect within the range predicted.
14.7.5 Assessment curves
The fourth stage is the calculation of assessment curves, which show the range of
petroleum volumes that may be found in the play or prospect, together with their
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probability of occurrence. These volumes can be compared with geochemical
petroleum charge volumes, so that no greater resource is placed into the play than
can realistically be charged from the source rock.
14.7.6 Economic aspects
The probability of a well finding petroleum is only one factor in successful
exploration. The financial risk and the potential profitability must also be considered,
both for individual prospects and the play as a whole. Whether a company is
commercially successful is dependent on the probability of geological success (i.e.
play assessment) and four financial parameters:
1. Potential profitability of the venture.
2. Available risk investment fund.
3. Total risk investment.
4. Aversion to risk.
Elaborate aids to help exploration decision making involve sophisticated
quantification of these commercial parameters. Computer simulation techniques may
then be used to aid the decision-making process and to determine the amount of risk
the investors’ finances can tolerate. Finally, companies are at the mercy of world oil
markets and the whims of governments, both of which can make any calculations
null and void.