14-the petroleum play

Shell Special Intensive Training Programme

Insole Allan of 18 ©Univation

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



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.



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.



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.



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



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



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.



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



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



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.



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.



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.



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



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.



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.



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.



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



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.