GeoCh2

Well Control11

C O N T E N T S

1.WHAT IS A PETROLEUM PLAY

2. RESERVOIR

3. SEAL

4. SOURCE ROCK, MATURITY ANDMIGRATION

5. TRAP

6. TIMING

7. RISK ANALYSIS

8. EXPLORATION TOOLS

The Petroleum Play22

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LEARNING OBJECTIVES:

The objectives of this chapter are to provide the engineering student with the basicconcepts used by Explorationists (Geologists and Geophysicists) in the search fornew oil and gas fields.

The important Geological concepts of the petroleum play are introduced through themain controls on petroleum accumulations, namely:

• Reservoir

• Seal

• Source rock and migration path

• Trap

• Timing

These controls are introduced together with a formal method of analysing the chanceof a successful outcome to an exploration well, in advance of its drilling. Knowledgeof these concepts is important in any discussions between engineers and explorationistsconcerning the value of an exploration portfolio.

At the end of this Chapter the student will be able to:

1. Describe and illustrate a petroleum play2. Know the difference between a lead and a prospect3. List the components of a petroleum play4. Describe exploration risk analysis5. Describe the control on poroperms in clastic and carbonate rocks6. Describe the palaeogeographic controls on reservoir development7. Describe the effects of burial on reservoir rocks8. Describe the elements of an effective seal9. Describe the elements of a good source rock10. Describe the effects of time and temperature on organic matter11. Describe why some source rocks produce oil, some gas and some both12. Describe maturity of source rocks13. Describe primary and secondary oil migration14. Describe the difference between a stratigraphic and structural trap15. Describe the traps formed around salt domes16. Describe why timing of source rock generation and trap formation are important

Department of Petroleum Engineering, Heriot-Watt University 3


1. WHAT IS THE PETROLEUM PLAY?

In hydrocarbon exploration, favourable geological conditions are sought with areasonable chance that a well drilled in the location will encounter a significantvolume of hydrocarbons. The method by which Explorationists (the collective nounfor Geologists, Geophysicists and Geochemists) evaluate the geological conditions isthrough a concept of the petroleum play. The petroleum play is a perception (ormodel) of how a specific region of the Earth’s subsurface may be an appropriate targetfor exploration drilling. More specifically, how a:

• producible reservoir (the rock with its connected pore or fracture system),• petroleum charge system (the source rock for the hydrocarbons and its migration

path to the subject reservoir),• regional topseal (the capping rock preventing migration out of the reservoir), and• trap (the geological features defining the physical limits to the reservoir rock in the

subsurface)

may combine to produce significant petroleum accumulations at a specific stratigraphiclevel. The US Geological Survey defines a play as a set of known or postulated oiland (or) gas accumulations showing similar geological, geographical and temporalproperties such as source rock, migration pathway, timing, trapping mechanism andhydrocarbon type. This essentially refers to already discovered fields rather that theconditions favourable for their discovery. In both definitions, the necessary attributesfor a successful petroleum play are the same and are of fundamental importance toexplorationists.

Explorationists within the operator (the oil or gas company that holds a licence toexplore on the behalf of a consortium of companies) are charged with identifying the3-D distribution of the various elements listed above (this is termed play mapping).The basic data that are used for this purpose include:

• Outcrops where the rocks of interest come to the surface,• Well data, where borehole measurements and samples of the rocks of interest are

available,• Seismic data (providing sub-surface imaging of the rock structure),• Geological studies by government geological surveys or industry contractors,• Information from discussions with professionals in other companies (scout data).

These data have to be synthesised and integrated into a series of play maps to showthe general areas of interest for further consideration by operator management andconsortium partners. Within these areas (usually large, from 10’s to 100’s or even1000’s of sq.km) the explorationists will also define specific leads (usually less than10 sq.km) which can be identified and worked into prospects after further datacollection or analysis. The operator may wish to drill prospects if a sufficent chanceof success can be demonstrated. A lead is unlikely to be drilled without further work.

A prospect is an identified trap (structural or stratigraphic) which:

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• has a reasonable chance of containing rock that has holes (i.e., is porous) which areconnected and can conduct fluid (i.e., is permeable),

• is older than the time which oil/gas was available (oil and/or gas migrates from asource rock on reaching thermal maturity),

• is in a location to which oil/gas could move (migrate)• is of sufficent potential size with enough confidence that oil will be found to warrant

drilling an exploration well.

The decision to carry out any exploration work will depend on various factors at eachstage. A play has to be identified before any exploration drilling starts. Initialsurveying will depend on the potential of the play. Detailed surveying will depend onthe size and number of leads identified. At any stage, the licence position with thelicencing authority (usually government) has to be agreed. Licencing rounds areusually offers for competitive bidding from consortia. Licences are usually awardedon the basis of the largest proposed work programme (usually surveys and wells). Anoperator will want to secure a licence before undertaking too much explorationexpenditure. For these commercial reasons, exploration is usually conducted in theutmost secrecy.

The size of a lead or prospect and the likelihood of success are often linked. Thegreater the possible return, the higher the level of risk (probability of failure) whichcan be taken. Several other criteria will be applied to the decision process. Theseinclude location (offshore/onshore, distance from facilities or export routes), taxregime of the relevant country and the characteristics of the operator (risk taker/avoider, cash rich, etc).

These vary so much between operators and between locations that it is hard to placelimits; however, the principles and the approach taken are always the same. There isno way to be certain about what a prospect contains before it has been drilled.Uncertainty is always present in exploration (and also in appraisal or even production)wells. The explorationists’ most important task, after identifying a prospect, is toprovide an estimation of technical risk. Risk analysis is a technique used to quantifythe technical uncertainty by estimating the probability of success in the key elementsof a prospect. The key elements are summarised as:

• Reservoir,• Seal,• Source Rock, Maturity and Migration Path,• Trap,• Timing

In this chapter, we will examine the method(s) by which the risk can be assessed ineach of these areas. Before proceeding, we can summarise this section:

(a) The Petroleum Play is a concept that allows explorationists to identifydrillable prospects.

(b) The Petroleum Play includes the integrated analysis of various data to addressrelevant geological elements:producible reservoir (RESERVOIR),



petroleum charge system (SOURCE ROCK, MATURITY, MIGRATIONPATH and TIMING),widespread topseal (SEAL), and geological structure (TRAP).

(c) The analysis of the Petroleum Play leads to the estimation of the probability ofsuccess for a particular prospect.

2. RESERVOIR

A rock is considered to be a potential "reservoir" if it contains holes (porosity is theratio of holes to solid) and the holes are connected over a significant volume(permeability is the ability of a rock to transmit fluid). Porosity determines the volumeof hydrocarbon the structure might contain (hydrocarbon-in-place) and permeabilitycontrols the rate at which it can be produced. In prospect appraisal, it is usually theformer that explorationists focus on, because porosity and permeability in manyreservoir rocks are often related (10% porosity often equates to a 1mD cut-off whichis thought necessary for oil production). The explorationist will thus be risking theoccurrence of rock that is greater than 10% porosity in order to define the reservoir.Exploration wells may be “successful” and find oil, but the rock might be soimpermeable that none of it can be economically produced! Sometimes theeconomics of oil can change (oil price rises, new technology, etc.), so it is oftendifficult for the explorationist to apply an appropriate cut-off value to estimate if thereservoir should be economically productive.

Porosity and permeability in clastic reservoirs are primarily controlled by the texturalproperties. The texture of a sediment is the concern of the sedimentologist and thereader is referred to the following Sedimentology Chapter 3 for a full appreciation ofthis subject. In the petroleum play, the two main elements of the textural descriptionare the size of the sand grains in the sandstone (grain size) and how variable the grainsare (sorting, where well sorted means all the grains are approximately the same size,poorly sorted means they are a wide range of sizes). Grain size and sorting have amajor control of porosity and permeability - collectively known as poroperms inpopular usage (figure 1).

100,000

10,000

1000

100

10

1

0.1

0 10 20 30 40 50

POROSITY (%)

PE

RM

EA

BIL

ITY

(m

D)

c

vf

grainsize

sorting

vp

vw

Figure 1

Textural control on

poroperm properties in

sandstones

(from experimental work

published in 1973 by Prior

and Beard & Weyl)

Grain size varies from very

fine (vf) to coarse (c) and

sorting from very poor (vp)

to very well (vw). Sorting

captures the variation in

grain size within a

sandstone sample

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The grain size and sorting will depend on the physical conditions where the sandsceased to be transported and so were deposited, prior to being lithified (i.e., thedepositional environment), because of:

• nearness or proximity to sediment source (coarser material is usually transportedover less distance).

• nature of sediment source which is known as provenance (an eroded sandstone willgenerate a different sediment than a granite, both in grain size and composition).

• the energy of the depositing currents

• fluctuations in depositing current strength and direction

The play mapping for a prospective reservoir unit will therefore include a model forthe deposition of sandstone (or other reservoir rock) through time and space. Theevolution of a reservoir is often represented by maps (horizontal or plan representations)and cross-sections (vertical section representations) for various stratigraphic levelsrecording the vertical and lateral distribution of rock types (figure 2). Depositionaltrends preserved in the rock record (described in detail in Chapter 3) can be used toinfer depositional patterns. Geologist's use the term palaeo- to indicate a feature inthe geological record. Hence the depositional patterns may indicate palaeo-slope,palaeo-wind direction and palaeo-drainage directions.

PLEIS

PLIO

MIOTERTIARY

BR

EC

CIA

PRE-TERTIARY

FLUVIAL SANDS AND SHALES

DEEP MARINE SANDS AND

IGNEOUS/METAMORPHIC BASEMENT

FZ

SW NERIDGE BASIN

3kmFZ FZ

FZ3km

FZ - FAULT

FZ

FZ

NFZ

FZ 3km

DEPOSITIONAL TRENDS

Figure 2

Sandstone development in

the Ridge Basin, California

(after Allen and Allen,

1990). Top: A plan map

view with the north (N)

arrow indicating

orientation. Below: A cross

section through the centre

of the map from north-east

(NE) to south-west (SW).

Pleistocene (PLEIS),

Pliocene (PLIO) and

Miocene (MIO) are

chronostratigraphic terms

(see Fig. 22, Chapter 1)

indicating that the 12km of

sediment in this basin was

deposited in the last 26

million years.



With an understanding of the depositional environments through time, reconstructionscan be made, with a reasonable degree of accuracy, even where the rock record is notpreserved or not sampled. These maps, made for the depositional system at the timeof deposition, are known as palaeogeographic reconstructions (figure 3).

For the Ridge Basin in California, reconstruction at time planes (stratigraphic level ofa particular time in the geological record) at time T1 (Miocene), shows the distributionof ocean with both deep water (submarine fans and turbidites1) and shallow water(coastal deposits1) sediments being deposited. By time T2 (Pliocene) the ocean haddrained and the region was dominated by a broad river system (braided fluvial channelsystem and braid plain1) over a wider area than covered by the earlier Miocene ocean.Such maps will show where the important trends lie (e.g., depocentres where thethickness reservoir of source rock may be deposited, depositional edge lines wherethe distribution limits of potential reservoirs are mapped) that might lead theexplorationist to target certain areas in preference to others.

1 - Sedimentological terms to be defined in Chapter 3

Figure 3

Palaeogeographic

reconstructions at two time

periods, in the Ridge Basin,

California, based on the

cross section (refer to Fig.

2). The locations of time

planes T1 (centre) and T2

(top) are shown in the

cross-section (below) and

represent reconstructions of

the geography in Miocene

and Pliocene times,

respectively, as the basin

filled up over geological

time

N

ALLUVIAL FANSBRAID PLAIN

BRAIDED FLUVIALCHANNEL SYSTEM

T2

T1

N

MOUNTAINS

LAND?

SUBMARINE FANS

OCEANTURBIDITES

COASTAL

DEPOSITS

LAND

T1

T2

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The textural maturity (i.e., how quartz-rich a sand is) is also important as diagenesistends to degrade the properties of immature sands (those with particles other thanquartz, which is quite stable) more rapidly. Provenance studies can be used to mapthe source of the sand material and its likely maturity (You should be aware of thedifference between “sediment source rocks” and “organic source rocks” and “texturalmaturity of sandstones” and “thermal maturity of source rocks”). The variability inpetrophysical properties (reservoir heterogeneity) is not too important at the explo-ration stage - these are more the concern of the production geologist. It is usuallyassumed (perhaps incorrectly in some cases) that the heterogeneity will be addressedby the field development scheme.

Porosity in sedimentary rocks usually declines with depth of burial (figure 4) and thisburial effect is often incorporated in a reservoir play map. Initial porosity in shales ishigher than that of sandstones at the time of deposition, but declines more rapidly asthe sediment expels waters.

100100 10101

SHALE SAND

POROSITY (%)

BU

RIA

L D

EP

TH

(km

)

0

2

4

6

8

Examination of thin sections and SEM images allow the relative timings of the mineralphases and cements to be determined by petrographic analysis. This analysis allowsthe sequence of diagenetic events to be determined (figure 5). Porosity-reducing andporosity-increasing phases of diagenesis can be identified. The latter is particularlyimportant as it can lead to anomalously high porosities (relative to those predicted infigure 4) at depths. This type of porosity is known as secondary porosity.

In the UK North Sea Central Graben, High-Pressure, High-Temperature (HPHT)reservoirs have become an exploration target and an important North Sea Play inrecent years, with >20% porosity resulting from secondary porosity events at up to6km depth (figure 6). Higher than normal water pressures (overpressure) in thereservoirs (the HPHT reservoirs are also highly overpressured) is another mechanismfor the preservation of reservoir porosity at depth.

Figure 4

Plots of log prosity against

depth for a range of shales

and sandstones

(after Allen and Allen,

1990).



TIME

PETROGRAPHIC SEQUENCE

- FULMAR SSTEARLY DIAGENESIS

DOLOMITE

DOLOMITE DISSOLUTION

QUARTZ OVERGROWTH

ILLITE

FELSPAR

ANASTASE

ANKERITE

ANKERITE DISSOLUTION

BITUMEN

CALCITE

POROSITY REDUCING

POROSITY ENHANCING

0.1510 0.30 0.45POTENTIAL POROSITY

PRIMARY POROSITY

SECONDARY POROSITY

WELL APRESENT DAY

WELL BPRESENT DAY

Nor

mal

Com

pact

ion

Cementat ion

BU

RIA

L D

EP

TH

(km

)

0

1

2

3

4

5

The primary fabric and mineralogy of carbonate reservoirs are also controlled bydeposition, through biological activity (e.g., the building of reefs by coral), and byprecipitation (small carbonate grains - ooids - are built by carbonate precipitationaround a nucleus). Carbonate reservoirs are often developed as coral reef build-upson a shallow marine shelf (figure 7). However, more importantly, it is diagenesis thatcreates most of the porosity in a carbonate reservoir. Diagenesis includes all changesthat occur to the rock once buried after deposition. Periods of post-depositional upliftand subaerial dissolution by rainwater (leaching of holes in the surface, karsts, orsubsurface, caverns, etc.) are particularly important as a reservoir-creating mecha-nism. Trends showing where this might have occurred (critical for explorationconsideration) can be mapped from regional information.

Figure 5

A petrographically-

determined sequence of

porosity-decreasing

cements for a reservoir

sandstone unit in the

Central North Sea (after

Wilkinson, et al., 1997).

Note phases of dissolution

of dolomite, felspar and

ankerite (a carbonate

mineral) also lead to the

development of porosity .

Figure 6

Porosity versus depth for

two North Sea Central

Graben wells plotted

against a “normal”

compactional loss of

porosity show loss of

porosity due to cementation

and then later increase of

porosity as the cement is

dissolved

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REEF FLANK FACIES

CORAL REEF

CARB. MUD MOUND

30m

1km

SHELF SLOPE

SALT

ANHYDRITE

SALT

CARB

CARB

The change of limestone into dolomite during diagenesis is accompanied by a volumereduction (16%) which can create microporosity betwen the dolomite crystals.Dolomitization is largely a depth-controlled phenomenom, so dolomite reservoirstend to be deep (or have been buried deeply). But, dolomite can also be deposited insome situations-such as in the evaporitic conditions of sabkha settings on desertcoasts. There are also other diagenetic changes. A result of the relative instability ofcarbonate under burial, pressure solution occurs, leading to the development of sub-horizontal discontinuities known as stylolites and potentially to reservoir development.The connection of voids, in order to provide permeability, is often a major concern incarbonates where large numbers of large pores (vugs) may have no effectivepermeability because the vugs are disconnected.

Carbonate rocks are relatively brittle (dolomite more so than limestone) and have atendency to break in response to structural deformation (i.e., fracture). Fracturetrends or zones may be mappable from seismic or from structural analysis.

Chalk is a special type of limestone, being made up from the shells of manymicroscopic marine organisms. Chalk reservoirs tend to be low permeability unlessfractured, as in the main producing zones in the Danish Offshore and the Austin Chalkof Texas.

The Upper Cretaceous Chalk of the Norwegian North Sea is a rather special carbonatereservoir. In one area (i.e., the Ekofisk Complex), chalks have provided a highporosity matrix where they have been redeposited by deep marine flows of sedimentfrom the shelfal areas. Early oil migration and overpressuring have ensured a highporosity (40-50%), high permeability reservoir that is quite unusual in a carbonate.The production mechanism is partly provided by a matrix compaction drive which hashad a dramatic effect, even at the sea bed where settlement of the platform wasobserved!

Key RESERVOIR points from this section to note are:

• In clastic reservoirs the reservoir quality is a function of grain size and sorting.• Grain size and sorting are a function of depositional environment.• Primary porosity generally (but not always) reduces with depth of burial.• Porosity and permeability development in carbonates is dominated by secondary

processes.

Figure 7

Cross section through a

carbonate (CARB)-

evaporite (SAL) dominated

platform of Upper Silurian

age from the Michigan

Basin, USA, showing the

development of isolated,

large coral reefs. (after

Allen and Allen, 1990)



3. SEAL

A seal is a fine-grained rock that prevents the oil migrating to the surface (whichhappens in many parts of the world - leading to natural oil seeps). In some situations,salt provides an effective seal but muddy, clay-rich rocks represent most seals. Theseal is an important component in a prospect. A fine-grained caprock seal is effectiveif the capillary entry pressure (figure 8) into the pores of the seal rock above anaccumulation is in excess of the buoyancy drive of the underlying hydrocarboncolumn. The field demonstration of this comes from Jennings (1987) where the 43m(140ft) oil columns equate to the entry pressure of the siltstones in a stratigraphic trap(figure 9).

A A'

A A'

Water Oil

1km

Dip Direction

0

0

Capillary Release Valve

LagoonFacies

BarFacies

43m

w

Bell Creek Montana

Small Pores

Large Pores

Hei

ght

0 1Water Saturation

A B

Figure 9

Map (top) and cross-section

(bottom) through the Bell

Creek oil field in SE

Montana. Eleven different

oil colums are trapped by

siltstone with 0.1 - 3mD

permeability (after

Jennings, 1987). The

capillary pressure curves

show low entry pressure in

the sandy rock (bar facies)

and high entry pressure in

the muddy rock (lagoon

facies).

Figure 8

Explanation of capillary

pressure.

Left - height of water rise in

a series of capillary tubes.

Right - Buoyancy pressure

needed to overcome

capillary entry pressure for

oil to displace water from

capillaries in a reservoir

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The importance of seals and trapping warrants the following explanation. let us definethe terms:

ρppetroleum density [kg/m3]

g acceleration due to gravity [m/s2]H height of hydrocarbon column [m]γγγγγ water-petroleum interfacial tension [N/m]r

sSEAL pore radius [m]

rr

RESERVOIR pore radius [m]θ water-petroleum contact angle [degrees]

Seal entry pressure (i.e. the pressure needed to breach seal)

Pcap

= 2 γγγγγ [(1/rs) - (1/r

r)] cos(θ) [Pascals] (2)

The minimum requirement to breach a seal is when

Pbuoyancy

= Pcap

(3)

Since P

buoyancy = H.g.[ρ

w - ρ

p]

Therefore

H = [2 γγγγγ [(1/rs) - (1/r

r)] cos(θ)] / [(ρ

w - ρ

p) g] (4)

In general, the term for the seal radius in equations 2 and 3 dominates as the seal hasmuch smaller pores than the reservoir. As a consequence, equation 4 can be (andusually is) reduced to:

H = [2 γγγγγ (1/rs) cos(θ)] / [∆ρ g] (5)

The contact angle is usually taken as being zero for water-wet water/petroleumsystems, so the cos(θ) term is unity, and the expression can be further reduced to:

H = [2 γγγγγ (1/rs)] / [∆ρ g] (6)

If we assume some typical values (water density of 1.013, oil density of 0.77, and aninterfacial tension of 10-2 N/m), we can see how the critical column height varies withthe radius of the pore throat of the seal (figure 10). Clearly, to use these formulae, itis necessary to estimate the “effective” pore throat radius for the seal. This is not easy,but shales and salt are often assumed to be effective seals (and this is borne out byobservations of hydrocarbon accumulations).



900

800

700

600

500

400

300

200

100

00.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 0.10 1.1

Seal Pore Radius (microns)

Pet

role

um C

olum

n H

eigh

t (m

)

4. SOURCE ROCK, MATURITY AND MIGRATION PATH

Petroleum originates (or is "sourced") from biologically-derived organic matterburied as sediment in sedimentary rocks. The sedimentary rocks, rich in organicmatter, which are capable of generating hydrocarbons are known as source rocks."Good" source rocks usually contain between 5% - 20% organic matter. Livingorganic matter, is comprised of four main chemical components: carbohydrates,proteins, lipids and lignins. Lipids and lignins are the most likely to be preserved andincorporated in sediment. Lipids occur in marine animals (fauna) and terrestial plants(flora). Lignins are found only in land plants. Lipids are predominantly oilprecursors (i.e., the material they contain may end up as oil); lignins, gas precursors.Palaeozoic land plant deposits (i.e., coals e.g., Carboniferous in SNS) tend to be gasprone; however, more recent ones (e.g., Tertiary in SE Asia) can also be oil prone.

Anoxic (low oxygen levels) conditions favour the preservation of organic matter. Thisis because the low oxygen availability restricts the action of organisms that wouldotherwise consume the deposited organic materials.

Source rocks are deposited in three main settings:

Lakes - isolated basins with poor turnover of the liquid column, allow the accumulationof land-derived (gas prone) or algal-derived (oil prone) organic matter. The EoceneGreen River Shale of the Western US and many of the SE Asian (particularly in China)source rocks were deposited in lakes (lacustrine).

Deltas - Deltas occur where rivers meet the sea (e.g., Nile, Mississippi). They arecharacterised by river channels with swamps and ponds (lagoons) in between.Organic matter can be derived from lagoonal algal concentrations or directly fromplants growing on the delta plain. Coals in the Tertiary sequence of Indonesia,originally deposited in swamps, form important oil source rocks. The lagoonal shalesin the Carboniferous (e.g. the Pumpherston Oil Shale outcropping at S. Queensferry,Lothian, Scotland, immediately underneath the Forth Rail Bridge) have been an oilsource. More commonly, the coals in the Carboniferous are the source for gas, asoccurs in the Southern North Sea.

Figure 10

Variation of critical

hydrocarbon height

controlled by pore-throat

radius of seal (water

specific density of 1.013 and

oil of 0.77)

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Marine basins - Marine basins, especially those with restricted circulation, form idealconditions for the accumulation of thick organic-rich source rocks. The KimmeridgeClay (North Sea) is a good example of a rich source rock (e.g. high organic content)in a marine shale. The Posidonia Shale (Posidonia is a marine fossil), of LowerJurassic age, is the oil source in the southern part of the Dutch Offshore and the ParisBasin and is a marine source rock. Zones of adundant upwelling in the oceans, wherethe fauna thrives because of the abundance of nutrients brought up as warm light watermeets dense cold water, can also lead to the formation of organic rich beds.

Source rocks are usually detected by the analysis of unwashed cuttings. The TotalOrganic Content (TOC) of a shale can be readily measured in the laboratory (byburning a sample and measuring the amount of carbon dioxide given off) andlaboratory pyrolysis (cooking to ca. 500oC and measuring the products) can determinethe petroleum yield of a source rock. TOC varies from 2-10+% in marine shale sourcerocks to >50% in a coal. Collection of headspace gas (gas given off by the drillingcuttings samples when stored in a can) can be used to determine source rock potentialof the sample. The analysis of source rocks is the role of the geochemist. Geochemicalsampling is routine on all exploration wells. The geochemical typing of shales isimportant to the subsequent tracing of the source of any discovered oils/gases.

Oil shales are defined as those capable of producing commercial quantities of oil. Thefirst industrial shale oil plant was developed in France in 1838 followed by the famousworks of James “Paraffin” Young at Bathgate in 1850. The spoil heaps from the latter(mined from the Pumpherston Oil Shale) can still be seen to the west of Edinburgh.

There are three components (known as macerals) of coal; vitrinite (gas prone), exinite(oil prone) and inertinite (not hydrocarbon prone). These can be readily identifiedpetrographically by geochemists. The reflectivity of vitrinite (vitrinite reflectance)to ordinary light under the microscope increases as the maturity of a coal increases.Anthracite, a mature coal, is shiny whilst brown coals, which are immature, are dull.Maturity is a function of time, temperature and pressure (as every cook knows).

Vitrinite reflectance, measured as a percentage of the light which is reflected back, isused to determine the maturity of a source rock. The vitrinite reflectance (R

o) is

correlatable with the main zones of hydrocarbon generation.

Ro < 0.55 Immature

0.55 < Ro < 0.80 Oil (and gas) generation

0.80 < Ro < 1.0 Cracking of oil to gas, gas generation

1.0 < Ro < 2.5 Dry gas generation

These levels are based on typical North Sea source rocks, Note that some oils (e.g.,Tertiary, SE Asia) can be sourced at much lower (R

o < 0.40 ) maturities because of the

nature of the source plant material.

Kerogen is the lipid-rich part of organic matter that is insoluble in common organicsolvents (lipids are the more waxy parts of animals and some plants). The extractablepart is known as bitumen. Kerogen is converted to bitumen during the maturationprocess. The amount of extractable bitumen is a measure of the maturity of a sourcerock. Bitumen becomes petroleum during migration. Petroleum is the liquid organic



substance recovered in wells. Crude oil is the naturally occurring liquid form ofpetroleum. Oils can be correlated with other oils (oil-oil) and with source rock extracts(oil-source rock) by the comparison of gas chromatograhy (figure 10).Chromotagraphy works by passing the oil (or extract) through a column of glass beadswhere the different hydrocarbon components can be separated. These components arethen flushed out and burnt. The peaks on a chromatogram record the amount of eachcomponent against time with the heavier ones being flushed out later than the lightones. In the chromatograms in figure 11, the reader is left to compare the two oils withthe source rock by matching up the peaks - the Audignon Field seems to match betterthan the Guajacq Field.

OilAudignon(Albian)

Source RockAire-sur-Adour(Upper Jurassic)

OilGaujacq(Albian)

The light fraction in oils is also subject to biodegradation during and after accumulation.Bacteria living in the subsurface will readily consume this fraction of the hydrocarbonas food and high temperature is needed to prevent this (at least 60ºC). Biodegradedcrude oils are notably heavier (more viscous) than unbiodegraded ones. Waxy crudesare also hard to deal with from an engineering point of view. Waxyness is also afunction of the source organic matter and lacustrine source rocks are notably wax-prone.

Kerogen is divided into reactive (most easily converted waxy, labile, part and themore woody, refractory part) and inert portions (figure 12). The proportions willdepend on the source organic matter and the depositional conditions of the sourcerock. The petroleum liquids expelled from each portion can be quite different incomposition and also have a different timing of expulsion (figure 13). A source rock

Figure 11

Comparison of gas

chromatograms of

saturated hydrocarbons for

oil-oil and oil-source rock

correlation (from the

Alberta Basin, W. Canada,

after Tissot and Welte,

1978). The verical scale is

a function of the

concentration and the

horizontal scale is time.

The heavier components

will appear to the right

hand side of the figure. See

text for further discussion.

1

16

may also have zones with varying components. It is important to assess the type ofsource rock and the temperature history of a source rock carefully to assess what mayhave been generated and when it was generated. This variation in source material andthe oil generation process goes some way to explain the variety of oils found inreservoirs.

Gas

Oil

Gas

>150oC100 -150oC

>150oC

GraphiteVery high T + P

Initial Oil

Kerogen

Labile

Refractory

Inert

Rea

ctiv

e

Petroleum generation takes place as the breakdown of kerogen occurs with risingtemperature. Temperature and time are the most important factors affecting thebreakdown of kerogen (a processes similar to domestic pressure cooking - all recipesgive a time and a temperature). As formation temperature rises on progressive burial(figure 13), an immature stage is succeeded by stages of oil generation, oil conversionto gas or cracking (to make a wet gas with significant amounts of liquids) and finallydry gas (i.e., no associated liquids) generation. Different proportions of componentsat various times in the evolution of hydocarbons is shown schematically in figure 13.

0

1

2

3

4

HYDROCARBONS

OIL

GAS

KE

RO

GE

N

DE

PT

H (

km)

DIA

GE

NC

AT

AG

EN

ES

ISM

ET

AG

DR

Y G

AS

WE

T G

AS

OIL

IMM

AT

UR

E

Ro

0.4

0.6

0.9

2.0

Figure 13

General scheme of

hydrocarbon formation as a

function of burial of source

rock. With burial the rock

undergoes a rise in

temperature and passes

through phases of change:

diagenesis, catagenesis and

eventually metagenesis.

Vitrinite reflectance, Ro, is

the maturity indicator.

Figure 12

Classification and fate of

organic matter in source

rocks (after Allen and

Allen, 1990)



Petroleum expulsion and primary migration take place as the oil leaves the source andenters the permeabile formation that will allow its migration to the ultimate reservoir(this is called the carrier bed and, often but not always, this might be the samestratigraphic unit that contains the reservoir). Primary migration is generally thoughtto be helped by the volume expansion associated with oil generation. Primarymigration is, however, difficult to observe directly and primary migration paths aredifficult to identify. Shales with silt beds (i.e., internal plumbing) can be efficientsource rocks (e.g., Posidonia shale). Expulsion efficiency (i.e., how much of what isgenerated is expelled) can be as high as 60-90%, if the source rock is very rich andpermeable, although this is difficult to estimate. For lean (low TOC) source rocks, theexpulsion efficiency may be very low. Following the earlier analogy of the "cooking"of a source rock, its is natural to call the location where that happens - the source"kitchen". Once in the carrier, secondary oil migration takes place from the“kitchen”, under buoyancy (i.e., gravity-dominated) flow (figure 13) to the reservoir.

Sourcekitchen

Poorcharge

Poorcharge

Goo

d ch

arge

Goo

d ch

arge

DEE

P

SHAL

LOW

The details of the migration might be quite complex as the oil has to move through apore system in the rock where capillary entry pressure is a strong controllingmechanism. A complex network of accumulations and flow paths can be shown bysimulations of secondary oil migration (figure 15, from Carruthers et al., 1997).Regional flows of aquifer water (known as hydrodynamic flow) in basins can alsoinfluence the efficiency of secondary oil migration. If these disperse the migrationfluid, this may reduce the efficiency of the process. Strong hydrodynamic flow mayalso help focus the flow. Secondary oil migration is prevented when the buoyancydriven flow is restrained by the capillary entry pressure of a caprock (i.e., it meets itsseal), breaking through when sufficient column has accumulated. Secondary oilmigration is thought to be a fairly inefficient process and requires "channeling" withina few carrier beds to be effective over long distances.

Figure 14

Migration from a mature

kitchen area by simple

buoyancy (after Allen and

Allen, 1990).

1

18

(d)

The oil migrates vertically

through the undisturbedsand and the vertically

aligned burrows until

another baffle is reachedand another micro

accumulation is formed

(a)

The vertical migration

trajectory is deflected by

the sedimentarystructure

(b)

Micro accumulation

beneath a high thresholdpressure baffle

(c)

Oil has reached the

capillary baffle andsaturation begins to

increase in the lower zone

Once in the reservoir, the hydrocarbon can be subjected to further changes due toincreased temperature, perhaps leading to the in-situ cracking of oil into gas. Bacterialaction can also degrade the oil by eating away the lighter ends and producing "heavy"oil, (<20OAPI). A gas charge into an oil column can also lead to the formation of asolid residue (known as asphaltene). Often the hydrocarbon will retain some linkswith the characteristics of source rock extracts, allowing the oil sources to beidentified. These may be multiple sources, or the hydrocarbon could be generated bymultiple events. Either way, and quite commonly, these can lead to petroleumcompositional variations which can be exploited to determine reservoir compart-ments (i.e., isolated fault blocks) .

��

10km

N

gasoil

G

W-E SECTION THROUGH TROLL

PALAEO OWC

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��

��

��

MOST LIKELY OIL MIGRATION ROUTES

VESLEFRIKK

OSEBERG

TROLL EAST

TROLLWESTOILPROVINCE

TROLLWESTGASPROVINCE

BRAGE

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OSEBERG OIL POPULATION

NORTHERN TROLL OIL POPULATION

VESLEFRIKK OIL POPULATION

Studies of the geochemical tracers and hydrocarbons contained within a series offields can be used to determine the filling history and to identify the best prospects,since the hydrocarbons may have varying properties and hence be of varying value.These geochemical studies also help the understanding of the compositional varia-tions within and between fields (figure 16). For the reservoir engineer there may bean interesting and complex story behind observed variations in oil properties.

Figure 15

Simulations of secondary

oil migration under gravity

and capillary dominated

conditions in a small

sandstone slab (courtesy

Dan Carruthers, 1997).

Figure 16

Filling directions for fields

in the Troll area,

Norwegian North Sea

(from Horstad and Larter,

1997)



Key SOURCE ROCK points:

• Source rocks for hydrocarbons are fine-grained organic-rich sediments (e.g.,coals, shales).

• Source rocks may be quite different stratigraphic units, in a location far away, fromthe reservoir rocks.

• Shales tend to source oils and coals, gas.

Key MATURATION points:

• Pressure and temperature sustained for a period of time are needed to generate oilor gas from a source rock.

• Gas tends to be generated at higher pressures and temperatures.

• The region in which maturation takes place is called the kitchen.

Key MIGRATION points:

• Migration from the source rock into the carrier bed is called primary migration.

• Primary migration is driven by pressure build-up caused by hydrocarbon genera-tion.

• Migration from the source kitchen area to the reservoir trap is called secondarymigration.

• Secondary migration is a gravity-driven processs controlled by pore-entry net-works.

5. TRAP

The hydrocarbon-trapping structure (trap) can be either a structural or a stratigraphicfeature. Hydrodynamic trapping has also been observed in areas where there is activeaquifer flow.

Structural traps are those caused by tectonic (figures 16-18), diapiric (figure 19),gravitational and compactional processes. These form at some time after depositionof the reservoir as a result of Earth movements. (See Structural Geology Chapter 4).

1

20

FootwallHanging wall

SECTION

1020

30

4050

PLAN

10

20

40

50

Trap

Trap

Footwall

Hanging wall

SECTION

1020

30

4050

PLAN

10

20

40

50

Trap

Trap

Hanging Wall Anticline

SECTION

PLAN

10

20

2020

30

30

40

30

40

50

Trap

Trap

Figure 17

Structural trap formed by

high-angle reverse

(contractional) fault in

cross-section (left)

and plan or map view

(right)

Figure 18

Structural trap formed by

normal (extensional) fault

in cross-section (left)

and plan or map view

(right).

Figure 19

Structural rollover traps

formed by extensional fault

movement (examples from

the Niger delta area).

Sometimes this movement

occured during deposition

leading to thicker sections

on the hanging wall.



Salt Dome

Traps

A structural (or stratigraphic trap) is said to be filled to spill point if there is sufficientoil to fill the structure to overflow (or “underflow”) at the spill point, which is theinfection point on the deepest closing contour of the map. If a structure is not filledto spill point, it implies insufficient oil has been generated or flowed along themigration path. (This is directly analogous (but inverted) to a sink or bath which hasits spill point at the overflow pipe). An alternative is that the top seal limits the columnheight.

Stratigraphic traps are those in which the geometry is inherited from the depositionalmorphology, subsequent diagenesis, facies changes (figure 21) or unconformities. Ineach case there is a stratigraphic reason for the juxtaposition of reservoir and seal ina favourable arrangement to trap migrating hydrocarbons. Stratigraphic traps never-the-less require structural tilting.

Facies Change

Facies Change

Unconformity

Hydrodynamic traps are comparitively rare, but occur when the hydrocarbon is tryingto migrate under the force of gravity against (or across) the downwards flow of aquiferwater.

Often traps have a combination of structural, stratigraphic and hydrodynamic trappingmechanisms. Active hydrodynamic flow can also produce tilted oil-water contacts,together with complex structural or filling histories. Fields commonly have differenthydrocarbon contacts in different parts of the overall trap (figure 22).

Figure 20

Structural traps associated

with salt diapirs. Salt is

mobile in the subsurface

and tends to rise to the

surface, aided by its low

density. Rising salt takes

on a distinctive "diapiric"

shape. Salt domes are very

common is some areas of

the world (e.g., Gulf Coast )

Figure 21

Stratigraphic traps

associated with an

unconformity (top) and a

lateral facies change

(middle). Where the facies

changes are transitional

“waste zones” can develop

(lower).

1

22

STATIC

TRAPCONFIGURATION

PRESSUREPROFILE

DYNAMICAQUIFERFLOW

AQUIFER FLOW

PERCHEDCONTACT

MIGRATION

MULTIPLECONTACTS

STRUCTURALCOMPARTMENTS

Key TRAP points:

• Tectonic features such as faults, folds and salt domes give rise to structural traps.

• Stratigraphic traps are formed by favourable stratigraphic arrangement of seal andreservoir rock.

• Active movement of fluid through the aquifer can lead to the tilting of hydrocarbon-water contacts and assist the trapping of hydrocarbons.

• Fields may have more than one hydrocarbon contact.

6. TIMING

One of the most important considerations required in a play evaluation is the timingof trap development relative to the timing of hydrocarbon migration. Stratigraphictraps due to depositional facies changes tend to pre-date any hydrocarbon generation.Unconformity traps and structural traps can develop much later in geological history,risking the loss of any early migration of oil. One aspect not to ignore is the possibilityof remigration from one trap to another. This occurs in basins where late phases oftilting may empty earlier traps.

Figure 22

Scenarios for oil-water

contacts due to aquifer

flow, filling history or fault

compartmentalisation.



The timing of oil migration can be determined by basin modelling. Basin modellingconcerns the (computer) modelling of the stratigraphy, structure and source rockhistory through time. If the stratigraphic section is reasonably complete, the timeperiod for each unit of rock can be determined using biostratigraphy. If the thicknessand time period of deposition are known, the rate of sedimentation can be estimated.For a kilometre of rock deposited over 1 million years at a uniform rate of 0.1cm/yr,the burial history can be shown graphically (figure 23a). This burial gradient is lesssteep compared to a burial history for a rate of 0.15cm/yr. Different rates ofsedimentation can be shown on a burial history curve. Since the sediment compactsas it is buried, the compaction can be incorporated as a reduction in thickness. Whengoing "backwards" from the preserved rock record that is seen in a well to calculatedepositional rates, de-compaction has to be taken into account. Successive units withvarying sedimentation rates can be used to build up a burial curve (figure 23b). Non-deposition or uplift and erosion can also be illustrated graphically (figure 23c). In thisway the burial history (also called geohistory) of a source rock through time can bedetermined. The vertical scale is usually depth, with temperature overlain. As anexample, burial histories for a Jurassic source rock in two well locations (one marginaland one axial to the basin) in an Australian basin are shown in figure 24.

C2 1 03

15

30

45

60

75

90

oC

2 1 03

NON-DEPOSITION

UPLIFT AND EROSION

1 m yrs

1 km

0.1 cm/yr

0.15 cm/yr

1 m yrs

0.1 cm/yr

0.15 cm/yr

A

B

NO COMPACTION 80% COMPACTION

NO COMPACTION 80% COMPACTIONper m yrs

2 1 0 2 1 0m yrs m yrs

m yrs m yrs

Figure 23

Illustration of burial or

geohistory curves. A) Over

a time period of 1million

years, a rock will be buried

1km for a sedimentation

rate of 0.1cm/year or 1.5km

for 0.15cm/yr. With 20%

compaction the rock will be

buried to only 800m or

1.2km respectively. B) In

this case a rock is buried at

the rate of 0.1cm/yr for

1myrs and then at 0.15cm/

yr (Vertical scale as in A).

C) If the rock undergoes

non-deposition it will

remain at a fixed depth

(which may also be a fixed

temperature). If the rock is

uplifted, its depth of burial

is reduced (and the rock

will cool).

1

24

The curves can represent (figure 23):

(a) different rates of deposition, with or without compaction;

(b) the sequence of burial history with different rates of deposition, and

(c) periods of non-deposition, or uplift and erosion.

A constant rise in temperature with depth (geothermal gradient) of 30oC/km hasbeen used to generate the temperature profile shown in figure 23(c) . Note the timescale usually has present day at the right hand side and time (in million of years beforepresent - MYBP) increasing to the left.

The geothermal gradient ensures that deeper rocks are at higher temperatures thansurface ones. The burial curve gives the residency time of the source rock in atemperature window and the time and temperature can be used to estimate a maturityprofile (in the same way that a recipe book has to give a time and a temperature to tellthe reader when something will be cooked). As rocks are uplifted, the temperaturereduces and maturation slows down or stops.

050100150

0

2

4

6

8

BASIN AXISMYBP

DE

PT

H (km

)

SEABED

0.5

0.7

1.0

1.3

Ro

BASIN MARGIN

0

2

4

Log (Ro)-0.8 -0.4 -0.2 0

050100150

0

2

4

DE

PT

H (km

)

Ro = 0.5

0

2

4

DATA

CALC

Log (Ro)-0.8 -0.4 -0.2 0

-

Figure 24

Geohistory curves for two

wells from the Bass Basin,

Australia. From these, it is

possible to determine the

maturity levels of the

various formations in the

basin axis (top) and basin

margin (bottom) (From

Williamson et al., 1987).



Because the rock record in a well is often incomplete due to unconformities and faults,these models need to be calibrated. The burial curves are calibrated by vitrinitereflectance (R

o) profiles in wells which record the maximum temperature to which

the source rock has been taken - indicated by the level of thermal maturation of theorganic material (figure 24).

The geothermal gradient can be overlain on the burial history to provide the thermalhistory (figure 22c). Knowing the time and temperature history of a source rockallows the timing of onset of oil and/or gas generation to be determined. The variationof geothermal gradient through the burial history period is another uncertainty whichcan be compared with the R

o data. The model of the thermal history is usually

presented as modelled vitrinite reflectance levels from which the oil and gas windowcan be determined (figure 12).

The burial history analysis also gives the periods of uplift and timing of structural trapformation. The relative timing of oil sourcing and trap formation can be determined.Hydrocarbons are often sourced in “kitchens” lying in the basinal (i.e., graben) areasalong side the uplifted (i.e., horst) areas where traps may form. The burial history ofkitchen and trap have to be determined. This can become a complicated 3-D basinmodelling exercise, which is becoming more common in exploration with thedevelopment of appropriate computer software.

The availability of mature source rock is a critical aspect in oil exploration. Many ofthe North Sea oil accumulations are to be found within the area of mature KimmeridgeClay (figure 25). Similar relationships hold for the gas fields in the Cooper Basin,Australia (figure 26). Maps of maturity levels of the major source rocks are criticalto the play evaluation. In the Cooper Basin, wells drilled in the mature source regionhave a 1 in 2 success ratio. In the post-mature zone there have been no discoveries.In the immature zone one well in 23 has been successful where gas has migrated upout of the deeper bain. If you were an Exploration Manager, you would certainly findthis map very useful.

��

�

�

�UNITEDKINGDOM

ORKNEYISLANDS

SHETLANDISLANDS

NORWAY

Regionalised Oil and Gas Maturation FairwayRo>0.6

NORTH SEABASIN

��OIL

FIELDSGAS FIELDS

MATUREKIMMERIDGIAN

OUTER BOUNDARY OIL PRONE TO MIXED ORGANIC FACIES OF LATE JURASSIC KIMMERIDGIAN

Figure 25

North Sea Basin showing

relationship between

discovered oil fields and the

maturity region of the main

source rock (from

Demaison, 1984).

1

26

SUCCESS RATIOS

IMMATURE PERMIAN 1 IN 23

MATURE PERMIAN SOURCE ZONE 1 IN 2

POST-MATURE PERMIAN ZONE 0

GIDGEALPAMOOMBA

0.9

S.A.QUEENSLAND

N.S.W

100 km

AUSTRALIACOOPER BASIN

MATURE (GAS)

POST-MATURE

GAS FIELD

PERMIAN COAL MEASURES

0.9Ro

2.0

0.9

The basin modelling (also called geohistory analysis), together with structural mapsand maps showing the location of source rock, can be assembled to produce a chargemodel for a prospect (figure 27). In this way the risk associated with the source rock,structure and timing can be assessed.

A'

A

Potential Source Area

Isomaturity Lines (Ro)0.8

0.8

Jurassic Source Rock

Isomaturity Lines (Ro)

2400

2200

2000

1800

0

4

0

4

JUR CRET TERT

Dep

th(k

m)

Dep

th(k

m)

0.6 0.6

0.80.8

1.0

0.6

0.8

1.0

1.0

H

3

2

1

1

1

2

2

3

3

A

B C

Key TIMING points:

Figure 26

Cooper Basin showing

distribution of gas fields

and the location of the gas

window (0.9 < R0 <2.0, after

Demaison, 1984)

Figure 27

Example of a prospect

charge model, applying

basin modelling (1D) to

various locations in the

basin (after Sluijk and

Nedelrof, 1984). A: map

view showing contours of a

source rock and “well”

locations; B: cross section

showing profile with iso-

maturity lines generated

from; C: three burial

curves for the three well

locations. Isomaturity lines

are lines connecting points

of equal maturity.



• Trap has to be older than the time of migration of hydrocarbons.

• Analysis of burial history of both reservoir and source is used to determine therelative timing of trap formation and oil generation.

7. Risk Analysis

With the play maps available for all the key elements (figure 28), it is possible forexplorationists to establish the probability of a prospect containing trapped hydrocar-bon in the various areas of a basin (figure 29). These “play chances” can be carriedforward into a more formal risk assessment.

Figure 28

Example of a play map

(from Allen and Allen,

1990).

1

28

Figure 29

Subdivision of the play map

(Fig. 24) into common-risk

segments These assess the

contributions of charge

(source, migration path,

timing), topseal and likely

trap development. In this

illustration, segment A is

considered proven (play

chance = 1). Any structure

mapped in this area would

have a very good chance of

being a successful prospect.

(from Allen and Allen,

1990).

Probabilities are assigned for each of the elements from 0, impossible or very unlikely,to 1, certain or very likely:

P(R) - The probability that there is reservoir developed in the prospect

P(SL) - The probability that sufficient unbreached, non-permeable seal continuouslyexisted above and lateral to the reservoir from prior to hydrocarbonmigration until the present day

P(SR) - The probability that there is a mature hydrocarbon source rock in thevicinity of the structure and that a migration path exists

P(TR) - The probability that a structural or stratigraphic trap is present

P(T) - The probability that the trap was developed prior to hydrocarbon migration

The Total Prospect Risk, P, is determined as:

P = P(R) x P(SL) x P(SR) x P(TR) x P(T)

For this to be statistically correct, the events should be independent. Note that evenif one was reasonably confident in all elements, P(R) = 0.75, P(SL) = 0.75, etc., theTotal Prospect Risk would be so high (P= 0.24) that it would be very unlikely that theprospect would be drilled with out more work. As a guideline:



"Needs more work” prospect P < 0.4High Risk Prospect 0.4 < P < 0.6Low Risk Prospect 0.6 < P < 0.8Very good prospect 0.8 < P

From equation 3, it is clear that if there is some uncertainty in any two or threeelements, it will not be possible to convince management that a drillable prospectexists. In this case there are a number of options - spend money to reduce uncertaintyto increase the chances of success (e.g., shoot more seismic), wait for someone elseto do it for you (by drilling a well and making a discovery nearby), or farm-out (i.e.,get someone else to take the chance by drilling the well at their cost and they take partof your percentage of the acreage), or relinquish the acreage (thereby saving the rentalcosts). Play maps are an important and valuable property to an oil company and as aresult they are usually very confidential!!

��

��

��

��

��

��

yy

yyyy

yyyyy

yyyyy

yyyyy

yyyy A'

A

100km

Onshore UK

Onshore Neth.

German SectorUK

Sector Netherlands Sector

CarboniferousGas Reserves

Permian Gas Play

Permian Gas Field

Erosional Limit of Rotliegendes Reservoir

Limit of CarboniferousSource Rock

Limit of ZechsteinSalt

��yy

Depositional Limitof Rotliegendes Reservoir

NN

A A'

SW NE

Poor Seal Good Seal

SilverpitSeal

RotliegendesReservoir

Source Rock

Carboniferous

Sand Coal

Salt

Location of Gas Field

Dep

th

Reservoirand

Source

The Permian gas play in the Southern North Sea is a good illustration of a petroleumplay that is very successful (figure 30) and well described. There are many gas fieldsacross the UK and Netherlands sectors of the North Sea, to the onshore Netherlandsand extending to the east into Germany. The successful gas-bearing fields occur instructural traps that lie:

Figure 30

A: Map of the Permian Gas

Play in the Southern North

Sea (after Spencer et al.,

1996)

B: Schematic cross section

A-A' (figure 28A) showing

the Rotliegendes reservoir,

underlying gas-producing

coals in the Carboniferous

and overlying Zechstein salt

seal. Where the

Rotliegendes passes into

shale (to the north-east)

Carboniferous sandstones

become the target reservoir.

A

B

1

30

• To the north of a line that defines the southern limit of the Zechstein salt seal,overlying the Rotliegendes reservoir

• To the south of a line that marks the northern extent of the deposition of sand in theRoliegendes.

• Within the area of underlying Carboniferous source rock

In the area to the north of the limit of Rotliegendes sandstones, gas fields occur inCarboniferous reservoirs, sealed by Silverpit shales. Structural traps identified withinthe play fairway (defined by the band of Rotliegendes reservoir with a top seal), havelittle risk. Reservoir, source, seal and timing are all certain. In this fairway, a highpercentage of exploration wells are successful (p > 0.8), the dry holes usuallyexplained by poor structural definition.

Key RISK ANALYSIS points:

• Risk Analysis involves the estimation of chances of exploration success (definedas finding hydrocarbons).

• The probabilty of a prospect’s exploration success is a funtion of the individualprobabilities concerning RESERVOIR, SEAL, SOURCE/MIGRATION, TRAPand TIMING. If these are independent, the total prospect probability is the productof the individual element probabilities.

• Risk analysis is an important exploration management tool to define whichprospects should be drilled, worked further, sold or otherwise given up.

8. EXPLORATION TOOLS

There are a whole range of sources of geological information that can becombined in the determination of the play chances presented in the last section.These data sources include:

Scout data: Information gained from the operator (officially or unofficially). Carelesstalk gives away secrets!

Regional geological data: National Geological Surveys, consultants reports onreleased data, outcrop studies.

Seismic data (refer to Chapter 5): 2-D traditionally in exploration, but increasingly3-D. For structural and stratigraphic mapping. Exploration seismic data are oftenacquired by the service companies as speculative data or “spec” data in advance of alicence round, at the service companies expense and sold many times over to variousoperators.

Well data: drilling records, wireline logs, cuttings (for biostratigraphy or geochemistry),cores.



Traded data: The Operator that acquires the well or seismic data, owns the data ontogether with members of the consortium. The data are held confidentially. The timewhich companies are allowed (by government) to hold confidential data varies fromcountry to country. In the UK it is currently 10 years. Companies can agree to anequitable exchange or “trade” of unreleased data.

SummaryIn this chapter we have seen what the critical geological issues are prior to drilling anexploration well. The engineer in a company will be expected to take exploration risknumbers into the economic evaluation of a prospect portfolio. This introduction to theconcepts that underlie the explorationist's evaluation will help the engineer appreciatethe quality and controlling issues behind those assessments.

1

32

ReferencesAllen, P.A., and Allen, J.R., 1990, Basin Analysis, Principles and Applications,Blackwell, Oxford, 451p. (Petroleum Play concepts covered in Chs. 10, 11)

Demaison, G., 1984, The Generative Basin Concept, in Petroleum Geochemistry andBasin Evolution, Demaison, G and Murris, R.J., (eds.) AAPG Memoir 35, p1-14.

Horstad, I., and Larter, S.R., 1997, Petroleum Migration, Alteration and remigrationwithin Troll Field, Norwegian North Sea, AAPG Bulletin, 81 (2), 222-248.

Jennings, J.B., 1987, Capillary pressure techniques: Application to Exploration andDevelopment Geology, AAPG Bulletin, 71, 1196-1209.

Tissot, B.P., and Welte, D.H., 1978, Petroleum Formation and Occurrence, SpringerVerlag, Berlin, 538p

Weber,1997

Wilkinson, M., Darby, D., Haszeldine, R.S., and Couples, G.D., 1997, Secondaryporosity generation during deep burial associated with overpressure leak-off: FulmarFormation, UK Central Graben, AAPG Bulletin, 81(5), 803-813.

Williamson, P.E., Pigram, C.J., Colwell, J.B., Scherl, A.S., Lockwood, K.L., andBranson, J.C., 1987, Review of the stratigraphy, structure, and hydrocarbon potentialof Bass Basin, Australia, AAPG Bulletin, 71(3), 253-280.



EXERCISE 1

Write a report on the Petroleum Play that occurs closest to one of the following:

your place of birth,your home location, oryour work location.

Be sure to address each element of the play as identified in this Chapter.

EXERCISE 2 (Page 34)

1

34

EXERCISE 2

Across

2. See 3 down

4. A Jurassic clay source rock for oil (10)

6, 12 A favourable site for the accumulationof hydrocarbons caused by lateral facieschanges in the reservoir unit (13,4)

11, 19. A light hydrocarbon (7,3)

12. See 6 across

13. A lead that’s worth drilling (8)

15. A 25º API hydrocarbon (3)

16. A gas source rock lithology (4)

20. See 8 down

23. A chemical change in the sedimentpost- deposition (10)

24. A fine-grained sealing lithology (4)

Down

1. A reconstruction of the topography at timeof deposition (16)

3, 2. Calculating the probability of successof a prospect (4,8)

4 The mother of hydrocarbons (7)

5. What occurs in the source kitchen (10)

7. Main petroleum exploration concept (4)

8, 20. What happened to a rock between itsdeposition and the present day (6,7)

9. A pressure that controls secondary oilmigration (9)



1

11 12

13 14

15

18

16 17

19 20

22

23

24

21

10

2

3 4 5

6 7

8 9

10. One of the critical elements of aPetroleum Play (6)

14, 22. Another name for a caprock (3,4)

17. A precursor of kerogen in land plants (6)

18. A critical ingredient for maturity (4)

21. A fluid interface in the reservoir (3)

1

36

1

11 12

13 14

15

18

16 17

19 20

22

23

24

21

10

2

3 4 5

6 7

8 9

A

A

A

A

A

A

A

A

A

A

A

A

A

A

B C

C

C

C

C

C

D

E

E E

E

E

E

E

G

G

G

G

H

H

I I

I

I I

I

I

I

I

I

K L

L

L

L

L

L

M WN

N

N

N

O

O

O

O

O

O

O

O

P

P

PP

R

R

R

R

R

R D EE GIIK M M R

S

S

SS

S

A PRT

T

T

T

T

AA CG H II PRRS TT

U

U

U

AA LN RT U

Y

Y

Y

A A ILN S SY

ANSWER: EXERCISE 2



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