David G. Smith Cedric M. Griffiths Stratigraphy Australia...

David G. SmithCedric M. Griffiths

Stratigraphy AustraliaDecember 1999

Undiscovered Resources of the Cooper Basin - SA

Stratigraphy Australia December 1999

Executive Summary

This report describes a second iteration and refinement of an earlier study (Griffiths, 1997) of theundiscovered hydrocarbon potential of the South Australian sector of the Cooper Basin. The study wasundertaken for Primary Industry and Resources, South Australia (PIRSA), the successor to theDepartment of Mines and Energy (MESA) for which the earlier study was undertaken. The study isindependent of both government and company interests in the basin.

The timing of the present report follows expiry of PELs 5&6 held by one joint venture since beforehydrocarbon discoveries were made in the 1960s. Although Santos has retained certain parts of thebasin as production licences, the greater part of its former acreage is being made available forexploration licences through a series of bid rounds, a process that began in 1998 and will continue into2001.

The new approach used here has resulted in a slightly reduced estimate for the total yet-to-findcompared with the ‘high’ estimates from the 1997 report. The distribution of undiscovered resourcesbetween ‘formations’ is however quite different, based as it is on trying to identify the shape of theunderlying distribution rather than extending the already-discovered distribution. The size of missingpools within each ‘formation’ is also predicted. The results are compared with those of the 1997 reportin the following table.

Results:

Predicted Total Gas(109 m3)

PredictedTotal Pools

ReservoirFormation

ObservedPools

P+P GasReserves

(1999)(109 m3)

1997APRAS hi

1999APRAS P50

1997 1999

1999 yet-to-find

(OGIP, P50)(109 m3)

Nappamerri 10 2.500 14.069 43.529 14 61 41Toolachee 35 58.170 228.069 80.784 53 84 23Daralingie 10 112.390 44.366 230.045 5 149 118Epsilon 35 16.538 14.613 48.686 35 67 32Patchawarra 125 139.860 514.493 245.457 163 157 106Tirrawarra 24 29.106 60.869 56.304 41 64 27Totals 239 358.564 876.479 704.805 311 582 347Aggregated 877.473 807.637 449

Explanation:

Reservoir Formation: The producing formation as recorded in the PIRSA data-base. Note that this may refer to diachronousunits with a range of biostratigraphic ages (see Appendices I and III for a discussion of the use of formations in this context).Observed Pools: The number of discretely identified pools of reservoired hydrocarbons in the PIRSA database associated witheach formation.P+P Gas Reserves (1999 ): proven and probable gas reserves from discovered fields identified in the 1999 PIRSA database.(P+P = P50 i.e. there is considered to be a 50% chance of this volume or greater).Predicted Total Gas:

1997 (APRAS hi P50): The more optimistic (hi) of the two P50 estimates of Original Gas In Place (OGIP) predictedusing the APRAS computer program in the 1997 study (Griffiths 1997, Appendix II).1999 (APRAS P50): The Original Gas In Place (P50) predicted using the APRAS computer program with the modifiedPareto approach used in this report.

Predicted Total Pools:1997: The 1997 estimate of total number of pools above commercial cutoff (taken as 0.14 x 109 m3)1999: The 1999 estimate of total number of pools above commercial cutoff (taken as 0.1 x 109 m3)

1999 Yet to Find (OGIP P50): The difference between the 1999 Predicted Total Gas and the Proven + Probable Gas Reserves.Note that this is in terms of OGIP50, not Sales Gas. An approximate value for Sales Gas is 50% of the OGIP figure. Thisfactor is based on data in the 1997 PEPS data base, for which the mean value of the product of recovery factor and shrinkageis 0.49 (median 0.51, standard deviation 0.1).Totals: the arithmetic unrisked sums of the individual formation values.Aggregated: the risked P50 aggregate of the formation values using APRAS.



The principal uncertainties in the 1997 study were considered to be:• The validity of existing play models for predicting the pattern of future discoveries• The number of undiscovered accumulations above an economic cut-off.

The explicit recommendations arising from the study were to:• Carry out a sensitivity study similar to Chen & Sinding-Larsen (1994a) and use the PRASS1

software to evaluate more thoroughly the likely number of accumulations. Then re-run theAPRAS analyses with those numbers.

• Identify an analogue for unconventional continuous-type gas resources in the Cooper Basin andcarry out a ‘cell’ analysis.

These recommendations were initially taken as the objectives of the present study. However, thefollowing practical considerations have caused us revise the objectives:• The recommendation to run sensitivity analyses using the PRASS1 software is not possible

because that software is now unobtainable and unsupported.• Although permeabilities in the deep Cooper Basin are low, they are not considered here to be so

low as to open up the possibilities of the continuous-type (basin-centred) gas resources referred toin the recommendations; there are however possibilities of other unconventional gas resources.

• The use of analogues has not been found helpful.

Instead, a new approach to estimating undiscovered resources has been developed and applied. Acombination of ‘slotting’ and genetic algorithms has been used (1) to estimate the shape of theunderlying distribution of pool sizes, and (2) to estimate the sizes of the missing pools. The results aresummarised in the above table.

The results suggest that the distributions represented by grouping pools by reservoir formation are notnatural. For example the pools lumped together as “Patchawarra” may comprise two or three series ofpools. The definition of an ‘anticlinal play’ for resource evaluation also combines multiple reservoirsystems and may obscure useful predictive stratigraphic relationships. We recommend that, before anyfurther work on undiscovered resources is carried out, a thorough sequence stratigraphic study of theCooper Basin should be carried out. Once the succession has been subdivided into isochronous geneticunits, an understanding of the extent of the successive depositional environments may be used to betterpredict the remaining resource potential.



Table of Contents:

EXECUTIVE SUMMARY............................................2

TABLE OF CONTENTS: .............................................4

INTRODUCTION........................................................5

A NOTE ON UNITS ...................................................5

REVIEW OF PREVIOUS WORK: GRIFFITHS (1997).....5

REVIEW OF PREVIOUS WORK: MORTON (1998).......6

Basin analogue...................................................6Basin plays .........................................................6Source generation...............................................6Discovery trend ..................................................7APRAS ................................................................7

SUMMARY OF UNDISCOVERED RECOVERABLE

RESOURCE ESTIMATES.............................................7

Gas......................................................................7Oil.......................................................................7

SENSITIVITY FACTORS OF RESOURCE ESTIMATION

METHODS ................................................................7

General comment on exploration maturity ........8Basin analogues .................................................8Basin Plays .........................................................8Source generation...............................................8Choice of statistical distribution ........................8Different approaches to re-sampling .................8Play by play or total basin .................................8Economic cutoff..................................................9Expectation that the data will fit a statisticaldistribution .........................................................9Basin sectors.......................................................9Lithostratigraphy versus sequence stratigraphy 9

A RESTATEMENT OF THE PROBLEM .........................9

Note on proven and conceptual plays ..............10Comment on nature of risk ...............................10

THE PETRIMES SOFTWARE AND APPROACH .......11

RESFIT: A NEW TECHNIQUE FOR ESTIMATING

UNDISCOVERED RESOURCES..................................11

DISCUSSION...........................................................16

RECOMMENDATIONS .............................................16

REFERENCES .........................................................17

APPENDIX I: COOPER BASIN PETROLEUM

SYSTEM ANALYSIS ................................................19

Identification of petroleum system componentsand their relative timing:..................................19

Comments......................................................... 19Discussion and identification of critical factors.......................................................................... 20

APPENDIX II: ANALOGUES FOR THE COOPER

BASIN ................................................................... 21

Basin origin...................................................... 21Structures ......................................................... 21Trap styles........................................................ 21Depositional environments: ............................. 22Candidate analogues ....................................... 22Comments on candidate analogues ................. 22

APPENDIX III: TOWARDS A PLAY ANALYSIS OF

THE COOPER BASIN .............................................. 24

Potential plays: ................................................ 24General comments on stratigraphic traps: ...... 25Unconventional plays: ..................................... 25

APPENDIX IV: ASSESSMENT OF

UNCONVENTIONAL GAS RESOURCES IN THE COOPER

BASIN ................................................................... 26

Introduction...................................................... 26Procedure......................................................... 26Analogues......................................................... 26Greater Green River area, western USA ......... 27Cotton Valley and Travis Peak formations,Texas-Louisiana............................................... 27Cleveland Formation, Anadarko Basin, southernUSA .................................................................. 27Elmworth and related gas fields, Alberta DeepBasin, Canada.................................................. 27Dnepr-Donets Basin, Ukraine ......................... 28Timan-Pechora Basin, northern Russia........... 28

APPENDIX V: SUMMARY TABLE OF FORMATION TOP

DEPTHS, FROM PEPS DATABASE .......................... 30



Introduction

This report describes a second iteration andrefinement of an earlier study (Griffiths, 1997) ofthe undiscovered hydrocarbon potential of theSouth Australian sector of the Cooper Basin. Thestudy was undertaken for Primary Industry andResources, South Australia (PIRSA), the successorto the Department of Mines and Energy (MESA)for which the earlier study was undertaken. Thestudy is independent of both government andcompany interests in the basin.

The timing of the present report follows expiry ofPELs 5&6 held by one joint venture since beforehydrocarbon discoveries were made in the 1960’s.Although Santos has retained certain parts of thebasin as production licences, the greater part of itsformer acreage is being made available forexploration licences through a series of bid rounds,a process that began in 1998 and will continue into2001.

The objectives of the present study were initiallytaken directly from the recommendations made byGriffiths (1997). Since the previous study wasundertaken, a comprehensive review by Morton(1998) has further compared the various methodsand their results, including those of our previousstudy (Griffiths, 1997), from a PIRSA perspective.This factor, together with some practicalconsiderations, has required a revision andrestatement of the objectives of this study.

A note on Units

For the purposes of comparison between differentestimates, we propose to express all estimates ofundiscovered gas in billions of cubic metres (Bcm,109 m3 or Bcm) and undiscovered oil in millions ofcubic metres (106 m3 or Mcm).

Review of previous work: Griffiths (1997)

Griffiths (1997) reviewed various methods ofestimating undiscovered resources and the resultsobtained by them. The method selected for a newanalysis was based on APRAS – the AnalyticalPetroleum Resource Appraisal System – developedover a number of years by the United StatesGeological Survey (USGS).

Using APRAS, Griffiths (1997) estimatedundiscovered resources for each of the sevenproductive formations in the Cooper Basin. Thestudy concluded that the most probable aggregatevalues for undiscovered hydrocarbons were asfollows:

Phase Level VolumeGas1 (P50) 172.1 x 109 m3

Oil2 (P05) 27.6 x 106 m3

LPG/condensate3 (P50) 79.65 x 106 m3

Notes:

1. Gas is yet-to-find gas in place (OGIP, P50), of which salesgas is likely to form approximately 50%, or 85,000 millioncubic metres. This was based on the low (less optimistic)APRAS estimate from the 1997 study; see below forfurther explanation.

2. For oil, the estimated (P50) value for oil in place was lessthan the already identified proven + probable (P50)reserves and the value was therefore ignored and the P05

value was used instead. The reason for theunderestimate is thought to be due to three factors: (a)overestimating the probability of gas in the analysis; (b)failing to identify probable new plays, and (c) setting thethreshold for economic accumulations too high.

3. The LPG/condensate value is the total resource, fromwhich identified reserves need to be subtracted in orderto estimate the yet-to-find. Other estimates have notgiven separate figures for natural gas liquids.

These estimates were substantially more optimisticthan those of Santos, the Bureau of ResourceSciences or MESA (PIRSA). Griffiths suggestedthat the undiscovered gas could reside inunidentified plays including unconventional gasreservoirs (see later discussion).

The main assumptions/constraints behind the1997 study were as follows:

• APRAS works by aggregating estimates ofundiscovered resources on a play by playbasis. Griffiths found that the only breakdownthat could be readily made was by productiveformation. Formations, however, are notgenetic units, and assumptions about thedistribution of pool sizes could therefore beincorrect.

• APRAS requires certain risk factors to be set,together with estimates of figures such asgas:oil ratio. These were generally estimatedfrom the observed data, without knowingwhether the known accumulations arerepresentative of the total population.

• Each ‘play’ was given a distribution of poolsizes, reservoir depths, and possible numbersof accumulations. Pool size and reservoirdepth distributions were estimated from theobserved (known) data. The number ofaccumulations above an economic cut-off of0.14 x109 m3 was taken (following an earlierstudy by Morton), to be twice (2X) theobserved number (X), but distributedaccording to two quite different models. In the



first (“High”) case the undiscovered poolswere assumed to be those numbered X+1 to2X in the discovery sequence; in the second(“Low”) case, the undiscovered pools wereassumed to lie within the total range (1 to 2X)of the discovery sequence. The total resourceestimated in the two cases is very different;clearly, the choice of method for estimating thenumber of undiscovered accumulations andtheir size distribution has an importantinfluence on the outcome (see below).

The principal uncertainties in the 1997 study wereconsidered to be:

• The validity of existing play models forpredicting the pattern of future discoveries

• The number of undiscovered accumulationsabove an economic cut-off.

The explicit recommendations arising from thestudy were:

• Carry out a sensitivity study similar to Chen &Sinding-Larsen (1994a) and use the PRASS1software to evaluate more thoroughly thelikely number of accumulations. Then re-runthe APRAS analyses with those numbers.

• Identify an analogue for unconventionalcontinuous-type gas resources in the CooperBasin and carry out a ‘cell’ analysis.

These recommendations were initially taken as theobjectives of the present study. However, thefollowing practical considerations have caused usto review the objectives, and we restate theproblem in a later section of this report:

• The recommendation to run sensitivityanalyses using the PRASS1 software is notpossible because that software is nowunobtainable and unsupported.

• Although permeabilities in the deep CooperBasin are low, they are not so low as to openup the possibilities of the continuous-type(basin-centred) gas resources referred to in therecommendations; there are however somepossibilities of other unconventional gasresources.

• The use of analogues has not been foundhelpful.

These issues are considered further in whatfollows.

Review of previous work: Morton (1998)

Morton gave the following figures for the known(produced plus remaining proven) recoverable gasand oil in the South Australian sector of the CooperBasin:

Gas (Bcm) Oil (Mcm)Produced 129 4.6Proven 101 2.3Total discovered 229 6.9

Morton reviewed the following methods ofestimating undiscovered resources; the associatedresource estimates are tabulated after the followingsummary of the methods.

Basin analogue

This method uses data from mature basins in whichthe petroleum system and other geological factorsare considered to be directly comparable to thebasin in question. Two methods (1 and 2 in thetable below) were used, the first of which wasquoted from Griffiths (1997) and which estimates atotal resource less than that already discovered –hence the zeroes in the table.

While suitable for a first-pass estimate for frontierbasins, Morton considers this an unreliable methodfor the Cooper Basin as it ignores most knowninformation about the basin. Our experiencefurther supports his view in that it is very difficultto obtain (from public-domain data) reliable anddirectly comparable data for the known reserves forcomparable plays in most other basins in the world.

Basin plays

In this method a number of factors are eachassigned ranges and a Monte Carlo approach isused to generate a range of estimates of the totalresource. All prospects are considered to beundrilled; their area is summed, and multiplied byestimates of thickness, net:gross etc.

The method relies on good knowledge ofprospective areas for each play, and depends on allplays having been identified. However it ignoresall data from discoveries, and is therefore morerelevant in less mature basins.

Source generation

This method estimates the probable amount ofhydrocarbons generated from the known sourcerocks. It requires estimation of both trappingefficiency and retention factors if it is to be used toestimate undiscovered resources, but it is useful inplacing an upper bound on the total potential



resource. A figure that is very much larger than theknown reserves could be used to suggest theexistence of one or more unsuspected plays; this isthe case in the Cooper Basin and Morton suggestedthe following as potential unexplored plays: low-permeability reservoirs, stratigraphic traps, andcoalbed methane.

Discovery trend

Morton’s preferred method is discovery trendanalysis, in which a model is derived fromobservations of the sequence of discoveries to datetogether with the assumption that the largeaccumulations are generally discovered early in thesequence (the so-called “creaming” effect).

Of the two commonly used models for the sizedistribution of pools, he selected the Paretodistribution on the strength of studies bySchuenmeyer and Drew (1983) and Drew, Attanasiand Schuenmeyer (1988). These authors suggestedthat the commonly observed lognormal distributiondesribes the sample, not the population. This isdue to selective targetting of the largest fields, aneffect that they referred to as “economictruncation” of the population distribution.

The Pareto model predicts a large number of fieldsand the end result can be very sensitive to theselection of an economic cutoff point on thisdistribution. The undiscovered resource figuresfrom this method are tabulated below with thosefrom the other methods; the numbers of economicaccumulations (post-1.1.98) estimated by Mortonusing this method is from 240 to 298 gas fields andfrom 48 to 60 oil fields; i.e. at least as many ofeach as have already been discovered.

APRAS

The APRAS method combines elements of theBasin Plays and Discovery Trend methods.Morton’s comments on the APRAS method usedby Griffiths (1997) are limited to the observationthat the study failed to predict the known reservesin some cases. It is worth noting here that Griffithsfound a power-law distribution gave a better fit tothe observed data than either a lognormal or aPareto distribution.

Summary of undiscovered recoverableresource estimates

The following summary table is based on Morton(1998), modified to give more detail.

Gas

Method Low P50 HighBasin analogue 11 0 0 0Basin analogue 22 108 193 277Basin plays 0 25 215Source generation ~5000APRAS (high case) 65 250 570APRAS (low case)3 0 85 500Disc.trend Pareto 41 60 83Disc.trend lognorm. 7 12 19

Volumes of gas in Bcm

Oil

Method Low P50 HighBasin analogue 11 150 169Basin analogue 22 15 20 26Basin plays 0 14 42Source generation ~9500APRAS (high case)3 0 04 5.5APRAS (low case)3 0 04 3.2Disc.trend Pareto 2 6 20Disc.trend lognormal 0.3 2 4

Volumes of oil4 in Mcm

Notes:1. Basin analogue 1: Griffiths (1997) used the example of

the Frio Fm, Gulf Coast, for a volumetric estimation ofCooper Basin undiscovered resources.

2. Basin analogue 2: Morton (1998) made this estimatebased on the worldwide statistics used by Klemme(1984).

3. In several cases the APRAS estimates of Griffiths (1997)predicted less than the already discovered reserves.

4. Griffiths made a separate estimate of total reserves ofnatural gas liquids (LPG and condensate); this has notbeen added in to the table as comparable figures havenot been generated for the other methods.

Morton concluded that the Basin Analogue andSource Potential methods were unreliable,implying that the Basin Plays, Discovery Trend andAPRAS methods were to be preferred. He furthercommented that some “undiscovered” CooperBasin hydrocarbons may have been found alreadyin the overlying Eromanga Basin; he regarded thisscenario as especially likely for oil, making CooperBasin oil prospects more limited.

Sensitivity factors of resource estimationmethods

Given the very large range of variation among theestimates resulting from the different methodsoutlined above, it is important to consider thefactors to which each is most sensitive. In somecases, this consideration of sensitivity can only besubjective and qualitative.



General comment on exploration maturity

An inescapable factor in all methods is that theCooper Basin is as yet relatively thinly explored:Morton (1998) reports a total of 298 newfieldwildcats drilled in the SA sector of the basin to1.1.98. Given a prospective area of approximately30,000 km2, the mean drilled density is 100 km2

per well. Given that the distribution of wildcats isvery uneven, there are substantial areas of the basinwith a much lower density of exploration drilling.Several of the estimating methods would be greatlyaffected if a significant new play were to open up.

Basin analogues

Here the main problems are that (a) no two basinsare alike; (b) there is no unique way of classifyingbasins into groups of basins that behave similarly;(c) there is no such thing as an average basin withinany such grouping; and (d) the method depends onthe comparator basin(s) being completely maturefor exploration.

Hence, in general terms, the method is verysensitive to the choice of comparator basin (in thecase of direct comparison with a single basin) or tothe combination of (i) choice of classificationscheme and (ii) correct classification of the basininto the chosen scheme.

Basin Plays

Given good understanding of the petroleum systemthis method should give good results but it isnevertheless sensitive to the possible existence ofone or more unknown plays, or even to imperfectunderstanding of a proven play. Mortonrecognised this problem and identified someprobably poorly explored plays as examples,choosing to use some “average” field values inorder to try to bring them into the estimate.

The basin plays method could therefore seriouslyunderestimate the total resource.

Source generation

This method produces very large numbers for thetotal amount of hydrocarbon generated in theCooper Basin, which shows that hydrocarboncharge is not itself a critical factor. However, thesize of the estimate means that the result will bevery sensitive to small changes in factors applied torepresent trapping efficiency and/or retention.These are virtually unknowable (other than by thereverse calculation of using the source generationmethod to estimate them).

Choice of statistical distribution

The discovery trend methods work by trying to fit asimple mathematical curve to the known number offields and distribution of field sizes. The choice ofmodel distribution can influence the outcome.

Morton chose the Pareto distribution in preferenceto the lognormal. The fact that the lognormaldistribution appears to provide a good model inmany cases may be due to the effect described as“economic truncation” by Schuenmayer and Drew(1983) and Drew et al (1988). In the view of thoseauthors, the lognormal distribution describes thesample distribution rather than the underlyingpopulation distribution. Since the objective is topredict the undiscovered resources, it is thepopulation distribution, and not the sampledistribution, that is sought.

Griffiths (1997) used the lognormal distribution asit was built into the APRAS software; he noted thatthere was a better fit of the observed data to apower-law distribution. A fourth distribution, theparabolic fractal distribution, has beenchampioned for global hydrocarbon resourcestudies by Laherrere (1996) but has not so far beenapplied in the Cooper Basin.

Different approaches to re-sampling

Griffiths used two end-member approaches to thequestion of the number of accumulations, whichwas distributed either from X to 2X (where X is thenumber of known discoveries), or from 1 to 2X. Inthe first case the size distribution of undiscoveredaccumulations will include as many large pools asthose already discovered and there is no allowancefor the “creaming” effect. In the second case, thetail of the distribution is extended and it is theextended distribution that is resampled, thusreducing the predicted occurrence of largeundiscovered fields. Subjectively, and on the basisof experience, the second approach is morerealistic, so long as the possible discovery ofanother field as large as Moomba or Tirrawarra canbe ruled out.

Play by play or total basin

Morton’s estimates (using both Pareto andlognormal distributions) were for the entire basin;Griffiths’ APRAS estimate was aggregated fromestimates for the individual productive formationsas identified in the PEPS database, an approach thatbrings its own problems, as discussed below.



Economic cutoff

While of importance for determining the number offields, this factor may have less effect on the totalresource estimation, in an immature basin, as thecutoff point is likely to be among small field sizes.For estimating the remaining undiscoveredresources in a mature basin, economic cutoff islikely to be more important, especially when usingthe Pareto distribution. (The lognormal distributionhas the effect of economic truncation built into it,as discussed above.)

Expectation that the data will fit a statisticaldistribution

Modelling and estimation are much simpler if itcan be assumed that the population to be estimatedis sufficiently “natural” that one of the variousavailable statistical models is likely to fit itsdistribution. Selection of the model is dealt withabove, but a separate issue is the question ofwhether or not the data should be statistically well-behaved at all. Factors affecting this mightinclude:

• Artificial vs natural boundaries to the basin(e.g. does the artificiality of the politicalboundary between QD and SA interfere withthe assumption that the SA sector of the basinshould have an internally well-behaveddistribution of field sizes?). See “Basinsectors” below for further discussion.

• The fact that many “fields” are comprised ofgeographically coincident pools some of whichwould be individually too small to beeconomic.

• Use of formations (in Griffiths’ case) ratherthan genetic units. See “Lithostratigraphyversus Sequence stratigraphy” below forfurther discussion.

Basin sectors

The division between the South Australian andQueensland sectors of the Cooper Basin is arbitraryand unrelated to the geology; can resources beexpected to be partitioned between the two state’ssectors in a proportionate manner? In fact, theproven oil and gas reserves are distributed quiteunequally, with about 217 x109m3 (1,400 MMboe)in SA and 91 x109m3 (586 MMboe) in Queensland,although the number of discoveries is about thesame (around 150 in each state). Of fields withmore than 15 x109m3 , South Australia has 5 butQueensland has only 1. This is despite Queenslandhaving a much larger proportion of the basin’s totalarea.

While the basic stratigraphy of the two sectors isessentially the same, the Eromanga Basin isgenerally more thickly developed in theQueensland sector, and the Cooper Basin in theSouth Australian sector. This is reflected in thedistribution of fields between the two sectors; onlyQueensland has significant numbers of fields inwhich the primary reservoir is in the EromangaBasin. At a more detailed level, there are (forexample) virtually no Tirrawarra Formationreservoirs in the Queensland sector. Wecker et al(1996) discussed the petroleum systems in thenorthern (QD) basin. This part of the basin hastended to be downgraded because of the perceivedlack of anticlinal structures together with poorreservoir quality in the Permian.

Thus, although the SA/QD division is apparentlyarbitrary, there are some ‘natural’ differencesbetween the two sectors and it should be noted thatresults obtained from one sector’s data shouldprobably not be applied to the other withoutsuitable modification.

Lithostratigraphy versus sequence stratigraphy

In the 1997 study the remaining reserves wereconsidered on a formation-by-formation basis.Given that formations are not natural depositionalsystems, it would be preferable to treat reserves bystratigraphic sequence, where a sequence is a unitwith true chronostratigraphic significance.

We considered using the available scheme ofpalynological zones as a substitute for a sequencestratigraphic scheme, but the reservoir units are notsufficiently closely tied to palynozones to makethis approach practicable. Also, (a) palynologicalstudies are carried out on only a small proportion ofwells drilled, and (b) palynology does not work onthe deeper sections, where the spores areunidentifiable because of the high thermal maturity(J. Morton, pers. comm.).

We have therefore had to go back to thelithostratigraphic approach, with the caveat thatformations are conventional and not natural units.We understand that sequence stratigraphic methodsare now being applied to the Cooper Basin, and thepresent analysis could be usefully repeated on thebasis of any such new breakdown of the basin’sstratigraphy.

A restatement of the problem

At this point it is worth attempting to restate theproblem, rather than merely re-run the variousmethods described above. The overall problem of



estimating undiscovered resources in the CooperBasin, omitting the question of reserves growth inknown discoveries, comprises the following parts:

1. How much remains to be discovered in provenplays, i.e. what is the number and sizedistribution of undiscovered accumulations?

2. What is the probability that one or more

unproven plays exist? 3. If such plays exist, what is the probable

number and size distribution of pools in each?

The previous attempts at estimating undiscoveredresources in the basin have largely focussed on thefirst part only of the total problem, although thevarious methods are to some extent applicable tothe third part also. The third question however isconditional on the second, and it is here thatperhaps the greatest uncertainty lies. We can seethe following ways of tackling this issue of thepotential existence of undiscovered plays.

1. The play concept can be ignored altogether,and the undiscovered resources of the basinestimated as a whole.

2. Try to model a discovery process in which newplays are opened up during the course ofexploration of the basin. It should be possibleto document the discovery history of theCooper Basin in terms of plays, though we donot have sufficient information to do this.Based on the discovery history of other basins,for instance the point(s) in the explorationmaturity of other basins at which new playsopened up, the possible distribution of thenumber and pool sizes of undiscovered playscould be modelled.

3. First, identify and define the proven playssufficiently stringently that their individualdiscovery history trends can be modelled andprojected into the future. Second, estimate thepotential for undiscovered plays, model thepotential number of such plays and the numberand size distribution of accumulations in each,and estimate the range of possible additionalresources contained in them.

Note that the above approaches are increasinglydependent, from (1) to (3), on careful definition ofexisting plays and assigning individualaccumulations to them. This is the step that wehave been unable to take from the data available tous. It is also the reason why Griffiths (1997) wasforced to use formations as a crude substitute forplays in the APRAS analysis. Further, it is abarrier to the constructive use of analogues from

other basins. It may be that further attempts toestimate the undiscovered resources of the basinwill be impossible without a full petroleum systemand play analysis of the basin (or, without access tosuch studies if confidential). We started such ananalysis (see Appendices I-III) but it is not reallywithin the scope of this study.

The potential for undiscovered plays might beestimated, for example, by assessing the volume ofunexplored rock in the basin (based on distancefrom nearest well and/or seismic survey), as well ason a Delphi (multi-expert) approach to the possibleidentity of untested plays in the basin (seeAppendix III where we have listed some of thespeculative plays that have been put forward in theliterature).

Note on proven and conceptual plays

Exploration proceeds on the basis of plays and playconcepts, where plays are operational groupings ofdiscoveries and prospects that share certain keyfeatures of their petroleum geology such asreservoir, trap and charge system. Conceptualplays add to the range of exploration possibilities,often by reference to proven plays in analoguebasins. Has the dominance of essentially a singleplayer in the Cooper Basin skewed theunderstanding of play concepts in the basin to thepoint where significant prospects have beenmissed, and can this effect be allowed for in ananalysis such as the present one? We commentbelow on the distinction between probability (risk)of occurrence of an accumulation, andprobability/risk of its being discovered; use of aninappropriate play scheme may greatly reduce theprobability of discovery by steering explorationeffort elsewhere.

Comment on nature of risk

It is worth distinguishing between the risk ofoccurrence of an accumulation and the risk offinding it (exploration risk). We are mainlyconcerned in this study with the risk of occurrenceof oil and gas accumulations, without regards tohow difficult they may be to find.

The two kinds of risk can become confused. Thetendency for accumulations in the Cooper Basin tobe associated with anticlinal structures is anobvious case: large positive structures are relativelyeasy to identify on seismic and therefore makegood drilling targets – they have low explorationrisk (historically the success rate in the CooperBasin is between 40% and 50%). A concentrationof successful drilling activity on these areas maylead to the conclusion that these are also the areasmost likely to have oil/gas accumulations. On the



one hand, this may indeed be the case; (a) thepositive structures were present as topographicfeatures from the beginnings of basin formationand are therefore associated with availability ofcoarse clastics; (b) they are a natural locus for bothstructural and unconformity traps, and (c) they actas focal points for hydrocarbon migration. On theother hand, plays that are not related to theexistence of structural highs will be inappropriatelyassigned a high exploration risk, where the riskagainst the existence of such accumulations mayactually be low. We are presently unable to assigna probability to the numbers of accumulations inthis category.

The PETRIMES software and approach

In a series of papers from 1983, Professor P. J. Leepublished an approach to undiscovered resourceestimation based on a maximum likelihoodestimation, discovery process modelling, and anunderlying lognormal distribution of pool sizes(Lee and Wang, 1985; Lee and Singer, 1994; Lee,1999). The computer-assisted system PETRIMES(PETroleum Resource Information Managementand Evaluation System), is primarily used to:

• estimate remaining reserves in a producingpool or field;

• estimate undiscovered resources in a play;• provide information for economic analysis;• validate exploration concepts against play data.

The system was established in 1984, and has beenupdated. The following versions are currently inuse:

• PETRIMES/W, Version 5 (1998); NationalCheng Kung University, Tainan, Taiwan

• PETRIMES/HP, Version 4 (1993); GeologicalSurvey of Canada, Calgary, Canada

• PETRIMES/PC, Version 3 (1993); GeologicalSurvey of Canada, Calgary, Canada

We obtained a copy of the beta version ofPETRIMES/W from Prof. Lee and attempted toapply it to Cooper Basin data. Unfortunately theWindows version that we received was designed inTaiwan for Chinese use and many of the editingfunctions and parts of the user interface are inChinese. In addition to this, and while trying tocorrrect some of the problems that arose in usingthe Windows version, Prof. Lee died in Canada.We have since been unable to use the software onCooper Basin data although the approach seems tohave potential, particularly in estimating missingpools from a distribution. The Unix version costsUS $5,000 from the Canadian Geological Survey.

RESFIT: a new technique for estimatingundiscovered resources

After considering the PETRIMES program and thepapers by Chen and Sinding-Larsen (1994a, 1994b)we again considered the criteria for an idealpredictive system for undiscovered resources. Theideal system should not only predict the totalamount of yet-to-find hydrocarbons but it shouldalso predict how those resources are distributed.Are the remaining resources distributed only insmall deposits close to economic cutoff, or is therea reasonable probability of larger targets stillremaining? Both Lee and Chen approached thisproblem by looking at lognormal or Pareto shapesof pool size distributions and manually fitting theobserved pools to the curve to demonstrate thepotential size of yet-to-find resources. If thisprocess could be automated it could provide auseful means of testing thousands of potentialtheoretical pool distribution curves against theobserved pool distribution while automaticallysuggesting the sizes of the missing pools.

With these criteria in mind, we have now written anew Fortran program ‘RESFIT’ which combines agenetic algorithm with a slotting technique to fit anobserved pool-size distribution to an ideal curve.

The procedure is as follows:

We use the following equation for the expectedpool size assuming an underlying Pareto populationdistribution:

nP = maxP

1

1

n( ) (1)

where:Pn is the size of the n th pool down from thelargest pool found in the subset underconsideration.Pmax is the size of the largest pool.θ is the shape parameter for the Paretodecay curve, usually between 0.95 and 1.0(Chen and Sinding-Larsen, 1994b).

The program proceeds by using a random numbergenerator to select values for Pmax and θ and thenfits the observed pool sizes to the randomly-generated succession. The comparator uses asequence matching technique (Bakke and Griffiths,1989; Griffiths and Bakke, 1990; Sankoff andKruskal, 1983; Sellers, 1974; Smith and Waterman,1980) that was initially developed for gene-typingbut has been successfully applied to inter-wellcorrelation. The success of fit in such a sequencematching approach depends on the ‘cost’ ofinsertion, deletion and substitution in the attempt to



fit one sequence to another. Take for example anobserved sequence of Pareto-distributed poolstaken from an underlying distribution where Pmax =2000 and θ = 0.95.

Underlyingseries

Observedseries

Predictedseries

2000 1840964 964 884629 629 576464 425367 367 336303 277257 257 235224 204197 197 180177 177 161160146 146 146134 134 133124 124 122115 115 113108 108 105101 101

The observed sequence was generated in thisdemonstration case by removing five of theunderlying values. The ‘predicted series’ is thepredicted underlying series output from RESFIT.

Because there is uncertainty in the observed fieldsizes RESFIT will score a successful match whenan observed pool size lies between two computedvalues. The prediction in this case is that themaximum field size is 1840 whereas the maximumobserved is 964. There are also missing fieldsaround 400, 300 and 200.

RESFIT will fit an observed pool sequence to anunderlying Pareto distribution of pool sizes andpredict the sizes of missing pools in the series. Thegreater the number of observed pools the greaterthe confidence in the shape factor θ. Thus well-sampled formations such as the Patchawarraconverge rapidly, while the Merrimelia does notproduce a useful match. Each producing formationin turn has been subjected to a RESFIT analysis.The analyses were repeated several times (at leastsix) for each formation. The median Pmax and θwere then used to generate a theoretical underlyingdistribution for the formation. The results areshown in Figures 1(a) to 1(f) for each of theformations individually.

Explanation of Figures 1 a-f:

Each graph plots predicted pool sizes (P(n)) againstrank (n), on a log-log scale, for an individualformation. Red dots show the actual sizes of poolsassigned to that formation Selected pools areidentified with arrows.

Note that the Patchawarra results (Figure 1b)indicate that either there are several plays that aregrouped together under ‘Patchawarra’ or the poolsize distributions in this formation are atypical(non-Pareto). It seems from the plots that there areat least two and maybe three series lumped togetherunder this pool identifier in the data-base. Thequestion of Daralingie and Nappamerri pools isalso interesting. There are very few Daralingiepools, with too wide a spread of values to fit into a‘natural’ grouping. It maybe that further sequencestratigraphic work will result in a significant re-evaluation of these pool affiliations. The samecomments apply to the Nappamerri Formation.

The proposed underlying distributions from theseRESFIT runs was then used in the APRASprogram to predict the probabilities associated withthe reservoired gas in the Cooper Basin (includingthat already discovered). The reservoir formationdepths used are tabulated in Appendix V. Theresults are shown in the table below.

As can be seen from these figures, the effect oftrying to pin down the underlying distribution in amore rigorous way than in the previous report is avalue of yet-to-find that lies between the 1997 highand low estimates. The APRAS aggregated resultsbased on the RESFIT calculations for eachformation give a total OGIP (P50) of 807 Bcm (109

m3) which represents a yet-to-find OGIP (P50) of449 (109 m3).

For comparison we have included an estimatebased on the ‘5/35’ rule that has been observed inmany basins, that is: the five largest fieldsrepresent around 35% of the total to be discovered.

This is obviously dependent on the discoveryprocess, and depends on how the stratigraphicsuccession is sub-divided but it may provide a veryrough reality check as to whether we aredramatically over- or under-estimating.



100

1000

104

105

1 10 100 1000

Median Pareto PoolsObserved

Med

ian

Par

eto

Poo

ls

Rank

Big LakeBookabourdiePondrinieKurundaCoonatieBimbayaFicusBalcamingaGidgealpa SthBindahSwan LakeCorreaPondrinie #11MeranjiMerupaScrubby CreekNariePelicanTaylor SouthBookabourdie #10MawsonKanowanaDeparanie

Figure 1(a) Tirrawarra Pools

100

1000

104

105

1 10 100 1000

median (seq) paretoObserved - adjusted to med(seq)

Poo

l Siz

e (

10

6 m3 )

Pool Rank

Toolachee WestBig LakeTirrawarraToolachee EastMoomba NthDaralingieDullingariDullingari NthMunkarieMundiMeranjiAndree/LelepAndree/LelepKanowanaFly Lake SWKernaCabernetBrumby #1MettikaToolachee 9/40Swan LakeTindilpieToolachee 5/23Goyder

Figure 1(b) Patchawarra Pools



100

1000

104

105

1 10 100 1000

median pareto seriesObserved pools

Poo

l Siz

e (

10 6 m

3 )

Pool Rank

Moomba SthKid/Aro/BagMunkarieMoomba NthCuttapirrieEpsilonKidman NthToolacheeVeronaBurkeArrakisKernaMundiKirbyMoolion NorthGoyderNapowieCoonatieDirkalaDaralingie #5GaranjanieKirraleeWoolooDorodilloYapeniGudi

Figure 1(c) Epsilon Pools

100

1000

10 4

10 5

1 10 100 1000

Pareto fitobserved pools

Poo

l siz

e (1

06 m

3 )

Pool Rank

Big LakeMoomba SthMoomba NthDullingariEpsilonBurkeDullingari NthMoomba EastMoomba #57Dilchee

Figure 1(d) Daralingie Pools



100

1000

104

105

1 10 100 1000

Median ParetoObserved Pools

Poo

l Siz

e (1

0

6 m3 )

Pool Rank

DellaGidgealpa NthKid/Aro/BagStrzeleckiMerrimeliaKirbyMarabookaPondrinieGidgealpa SthMuderaMeranjiSwan LakeCoonatiePennieMoolion NorthBecklerPelicanMunkarieLamdinaLepenaTirrawarraWanaraMaranaKidman NthTallerangieMerupaMoolionNapowieBimbaya

Figure 1(e) Toolachee Pools

100

1000

10 4

10 5

1 10 100 1000

Median Pareto PoolsObserved

Med

ian

Par

eto

Poo

ls

Rank

Merrimel ia(a)PondrinieMerrimelia(b)Coonat ieEpsilonMoorar iMer inda lPirramintaBookabourdieKirby

Figure 1(f) Nappamerri Pools



Discussion

The modified approach used here has resulted in aslightly reduced estimate for the total yet-to-findcompared with the 1997 report. The distribution ofundiscovered resources between ‘formations’ ishowever quite different, based as it is on trying toidentify the shape of the underlying distributionrather than extending the already-discovereddistribution. The prediction of the size of missingpools within each ‘formation’ is also new.

The utility of the ‘formation’ concept in relation toundiscovered resource estimation has beenquestioned in several places in this report, but untildetailed mapping and analysis has been carried out

on the basis of depositional environments there islittle more that can be done.

Recommendations

We recommend that, before any further work onundiscovered resources is carried out, a thoroughsequence stratigraphic study of the Cooper Basinshould be carried out. Once the succession hasbeen subdivided into isochronous units, anunderstanding of the extent of the successivedepositional environments may be used to betterpredict the remaining resource potential.

Summary of results:

Predicted Total Gas(109 m3)

PredictedTotal Pools

ReservoirFormation

ObservedPools

PP GasReserves

1999(109 m3)

1997APRAS hi P50

1999APRAS P50

1999“5/35 rule”

1997 1999

1999 yet-to-find

(OGIP, P50)(109 m3)

Nappamerri 10 2.500 14.069 43.529 110.868 14 61 41.029Toolachee 35 58.170 228.069 80.784 160.648 53 84 22.614Daralingie 10 112.390 44.366 230.045 277.917 5 149 117.655Epsilon 35 16.538 14.613 48.686 107.911 35 67 32.148Patchawarra 125 139.860 514.493 245.457 327.771 163 157 105.597Tirrawarra 24 29.106 60.869 56.304 148.048 41 64 27.198Totals 239 358.564 876.479 704.805 1133.163 311 582 346.241Aggregated 877.473 807.637 449.073

Explanation:

Reservoir Formation: The producing formation as recorded in the PIRSA data-base. Note that this may refer to diachronous units with arange of biostratigraphic ages (see Appendices I and III for a discussion of the use of formations in this context).Observed Pools: The number of discretely identified pools of reservoired hydrocarbons in the PIRSA database associated with eachformation.P+P Gas Reserves (1999 ): proven and probable gas reserves from discovered fields identified in the 1999 PIRSA database. (P+P = P50

i.e. there is considered to be a 50% chance of this volume or greater).Predicted Total Gas:

1997 (APRAS hi P50): The more optimistic (hi) of the two P50 estimates of Original Gas In Place (OGIP) predicted using theAPRAS computer program in the 1997 study (Griffiths 1997, Appendix II).1999 (APRAS P50): The Original Gas In Place (P50) predicted using the APRAS computer program with the modified Paretoapproach used in this report.1999 “5/35” Rule: This estimate is for comparison only. It is derived from the observation that the five largest fields in a basincommonly account for 35% of the total reserves of the basin; see text for further discussion.

Predicted Total Pools:1997: The 1997 estimate of total number of pools above commercial cutoff (taken as 0.14 x 109 m3)1999: The 1999 estimate of total number of pools above commercial cutoff (taken as 0.1 x 109 m3)

1999 Yet to Find (OGIP P50): The difference between the 1999 Predicted Total Gas and the Proven + Probable Gas Reserves. Note thatthis is in terms of OGIP50, not Sales Gas. An approximate value for Sales Gas is 50% of the OGIP figure. This factor is based on data inthe 1997 PEPS data base, for which the mean value of the product of recovery factor and shrinkage is 0.49 (median 0.51, standarddeviation 0.1).Totals: the arithmetic unrisked sums of the individual formation values.Aggregated: the risked P50 aggregate of the formation values using APRAS.



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YEW, C.C., MILLS, A.A., 1989. The occurrenceand search for Permian oil in the Cooper Basin,Australia. In: O’Neil, B.J. (ed), The Cooper andEromanga Basins, Australia, ProceedingsPetroleum Exploration Society of Australia,Adelaide, 1989, 339-359.



APPENDIX I: Cooper Basin PetroleumSystem analysis

A petroleum system comprises mature source,migration pathways, reservoirs and traps, in theirtime context. Analysis of the geology of a basin interms of its petroleum system(s) is a usefulapproach to understanding how it “works”. We are

aware of the dangers of too superficial an approach,but we have found it helpful in our attempt tounderstand the basin’s play concepts to summarisethe key features of the petroleum system. Much ofwhat follows is based on information in the recentvolume edited by Gravestock et al. (1998), withadditional material, especially from Boreham andSummons (1999).

Identification of petroleum system components and their relative timing:

System element Lithostratigraphic unit TimingSource Rock 1. Patchawarra Fm (coal/shale) Early Permian (Ass-Art)

2. Toolachee Fm (coal/shale) Late Permian (Kaz-Tat)3. Warburton Basin (hypothetical) Pre-Permian

Reservoir Oil: Eromanga Basin Jurassic-CretaceousTirrawarra Sandstone Late Carb-E. Perm (Ste-Ass)

Gas: Toolachee Formation Late Permian (Kaz-Tat)Daralingie Formation Early Permian (Kun-Ufi)Epsilon Formation Early Permian (Art-Kun)Patchawarra Formation Early Permian (Ass-Art)Tirrawarra Sandstone Late Carb-E. Perm (Ste-Ass)Merrimelia Fm Late Carb-E. Perm (Ste-Ass)Warburton Basin Pre-Permian

Seal Intraformational: Early to Late PermianRegional: Arrabury Formation Late Perm-E. Trias (Tat-Ans)

Roseneath Shale Early Permian (Kun)Murteree Shale Early Permian (Art)

Traps Stratigraphic component Early Permian-Late Permian(onlap/drape over topographic highs)Structural component E/L Perm boundary , ?compr.

Mesoz. – minor struct. growthEarly Tertiary compression

Maturation Earliest maturity Mid Permian (Nappamerri Tr.)Peak maturation Mid CretaceousEnd maturation Plio-Pleistocene

Comments

Source rock: The Patchawarra and Toolacheesource rock systems are both well proven. Of thetwo, the Patchawarra is volumetrically the moreimportant. Although Cooper-sourced oils areimportant in the overlying Eromanga Basin (Heathet al. 1989, Hunt et al. 1989), Eromanga-sourcedhydrocarbons have not been identified in theCooper Basin. Boreham & Summons (1999),based on analyses of oils, identify severalpetroleum systems and are able to distinguish oilsgenerated from Cooper vs Eromanga source. Afew Cooper Basin fields have additional

components likely to have been sourced from theWarburton Basin, though the identity of such asource remains unknown.

The volume of hydrocarbons that could have beensourced from the Patchawarra alone is more thansufficient to account for all known accumulationsin the Cooper Basin (Griffiths 1997); hydrocarboncharge is therefore not considered to be a risk in theanalysis of undiscovered potential.

Boult et al (1998) discuss the evidence in favour ofthe derivation of significant quantities of oil



trapped in the Eromanga megasequence fromwithin the Eromanga itself.

Reservoirs: Reservoirs exist in the underlyingWarburton Basin (weathered and fractured“basement”) and in the overlying Eromanga Basin,which also has its own source rocks.

Seals: The Arrabury Fm (Nappamerri Group),generally regarded as a regional seal separating theCooper and Eromanga basins, is not effective overthe whole area, and is itself a minor reservoir inplaces. The Roseneath and Murteree shales appearto be more effective, but most accumulations in theCooper Basin are sealed intraformationally.Availability of topseal is therefore not consideredas a significant risk. Faults are known to seal insome traps and to be conductive elsewhere; trapsdependent on fault seals therefore carry a riskwhich is distributed between 0 and 1 but thedistribution is unknown in detail.

Traps: Trap formation is not explicitly discussedin Gravestock et al (or elsewhere?). Many knowntraps are related to the existence of structural highs,which, although structurally controlled, areprobably also erosional remnants of the pre-CooperBasin topography. Onlap and drape of Permianstrata on to and over these features, which werethen reactivated (predominantly vertically), are theorigins of many traps. The age of formation ofthese traps is therefore early in basin history.

Wecker et al (1996) identify a subordinate Mid-Late Triassic structural event and a dominant LateCretaceous-Early Tertiary one – in the northernCooper Basin. First-order anticlines overliebasement-involved high angle reverse faults; thefaults sometimes cut the folds near their crests attop Toolachee Fm level, penetrating upwardsthrough the Cadna-owie Fm. Second-orderstructures between the major trends are similarlythick-skinned and were in place beforehydrocarbon generation starting in the EarlyCretaceous. Traps were probably breached in LateCretaceous-Early Tertiary tectonics, though not allstructures were affected; MIM focussed itsexploration programme on these. Simple anticlinaltraps are uncommon. There is potential for othernon-conventional plays involving lowside faulttraps and stratigraphic traps, but these are difficultto image with available seismic.

According to Wecker et al, the basal ToolacheeFormation is the primary target for conventionalgas reserves in their area of the northern CooperBasin. The Patchawarra Formation here has lowpermeabilities.

Maturation: Maturation took place mainly in themid-Cretaceous, post-dating both stratigraphic andstructural trap formation (though there is somemention of a minor structural event in the Tertiary).Some expulsion of oil could have occurred beforethe end of the Permian in the Nappamerri Trough.

Migration from mid-Cretaceous kitchens to then-existing traps needs re-evaluation according toGravestock et al. (1998). Lateral migration of>50km has been demonstrated in one case, from aPermian source to a post-Permian (EromangaBasin) trap (Boreham & Summons 1999), but is notnecessarily the rule. A map of oil and gas fieldsagainst vitrinite isoreflectance contours indicatesthat the gas fields tend to lie preferentially overhigher mature areas (1.0-1.3+) whereas the oilfields in the northern part of the basin lie oversource rock that is presently at about R0=1.0.Distribution of fields in relation to mature sourceand effective seal is briefly discussed byGravestock et al., who appear to be rather criticalof the limited attention that has been given to thiskind of approach, implying that there is more tolearn.

Discussion and identification of critical factors

• Source and charge: not a risk: several sourcesfor both oil and gas exist at many levels andmore than enough oil/gas has been generated.

• Maturity: No risk – abundant mature sourcerock, but risk of overmaturity affecting oil indeeper reservoirs.

• Trap formation: timing not critical thoughmechanisms incompletely understood

• Seals: Intraformational seals adequate in mostcases: regional seals also exist.

• Traps: Plenty of traps known to exist, but arethere significantly more than have beendiscovered?

• Timing: OK for mid-Cretaceous and youngerentrapment.

• Secondary migration: (source to trap): No risk:entire basin within reach of mature sourcerock. Details of pathways not discussed; mayaffect distribution of fields.

• Retention (trap integrity): Possible risks onfault seals: Tertiary tectonic event(s) may haveallowed leakage – possibly less important forCooper than for Eromanga reservoirs. Theregional Arrabury Fm topseal is known to beineffective. Also, Cooper-sourced oils arefound in the Eromanga Basin. Possibility ofleakage through tilting.



APPENDIX II: Analogues for the CooperBasin

One approach to the consideration of undiscoveredresources, and the possible existence ofunsuspected plays, is to look for analogue basins.This section of the report describes our search forsuch basins, although we have had a rather limiteddegree of success that we have had with thisapproach.

Any analogue for the Cooper Basin should sharemost or all of the following characteristics:

• Moderately mature for exploration• Intracratonic basin: origin controversial but

probably compressional• No outcrop – entirely sub-surface• Non-marine throughout, including periglacial

and/or post-glacial strata• Coal and/or lacustrine shale source• Proven and prolific petroleum system;

probably not limited by charge• Relatively undeformed• Majority of trap structures dependent on

simple drape and compaction over pre-existingstructural features.

• Hot basin – high heat-flow• Gas-prone with minor oil; significant NGLs

Some of the key characteristics requiring to bematched in an analogue basin are now discussed.

Basin origin

Because of the controversy over the origin of thebasin, the various basin classification schemes arenot greatly helpful for identifying analogues. Apak(1994) points out that the basin has been variouslyclassified as follows:

• Complex intracratonic (Klemme, 1980;Stanmore, 1989)

• Pericratonic (Veevers, 1982)• Interior sag basin (Middleton & Hunt, 1988;

Kingston et al 1983)• Rift basin (Yew & Mills, 1989)• Flexural basin (Watts, 1982)

Currently the two main contenders are:

1. Thermal sag (Gravestock & Jensen-Schmidt,in Gravestock et al. 1998), resulting fromcooling following the emplacement of granites.These authors postulate substantial glacially-generated relief as being present at the onset ofbasin formation, and as controllingsedimentation through to end-Early Permian.Structure growth began at around this time, notearlier.

2. Mildly compressional, according to Apak

(Ph.D., Thesis, 1994), in an overall NE-oriented compressional environment. Nomention of Late Carboniferous granites,although these are shown on his cross-sectionFig. 1.2.

Structures

Gravestock & Jensen-Schmidt (1998) explain thediversity of structural styles as being the responseof differently oriented pre-existing structures to ananisotropic regional stress field, without the need toinvoke changing predominance of different stressregimes.

Trap styles

Apak (Thesis, 1994) recognises the following:

Structural:• Anticlines• Drapes over pre-existing highs• Lowside fault closures: may require faults to

be sealing

Stratigraphic:• Lateral facies change - point-bar and channel

sandstones, shoreline sands

Combination:• Most Patchawarra traps are probably

combination – see below.• Onlap and subunconformity traps (downflank

to positive structures)

Comment:

Most traps in the Patchawarra Formation, wherefields typically comprise several stacked reservoirunits, lie on a spectrum between purely structuraland purely stratigraphic (Alan Sansome & JohnMorton, pers. comm.). In effect, a “field” could beconsidered to be an arbitrary location where thereis a sufficient geographical coincidence of reservoirunits to form an economically viable whole. Itmight be possible to construct a statistical model ofthe likely number of such “fields”.

Maturity of trap exploration: Apak (1994)considers that only a few of the stratigraphic andcombination traps can be considered to have beenexplored adequately within the basin. Furtherunderstanding requires reconstructions of 3-Ddepo-systems and establishment of time-stratigraphic units across the basin. A proposal touse climatically-based units is included underRecommendations at the end of this report.



Depositional environments:

The depositional environments of the Cooper Basinare entirely non-marine, comprising the following:

• Glacial/periglacial – Merrimelia Formation,where the highest quality reservoirs known todate are aeolian sands.

• Fluvial – Patchawarra, Toolachee, Daralingieformations – Point-bar sandstones are the mostcommon reservoir type. Risks associated with

locating such reservoirs are well-known(examples?) and depend on reliabledepositional modelling and seismic imaging.

• Deltaic – Epsilon, Daralingie, Patchawarraformations

• Lacustrine – Murteree, Roseneath shales –marginal (shoreline and deltaic) faciesimportant. Lacustrine shales important asseals.

Candidate analogues

Region Basin CommentsNorth America Illinois Cratonic. Oil only. Fluvial-deltaic in part (U.Mis.-Penn.). Anticlinal traps.

Uinta, Green River,Piceance

Lacustrine with fluvial and deltaic sandstones. Non-marine source.Tertiary. Wrong structural setting but explored for unconventional tight gasresources. Main reservoirs are pre-Tertiary.

Cherokee Platform Penn. plays range from stratigraphic to structural in fluvio-deltaic sands.South America Reconcavo Jur.-L.Cret., non-marine. Drapes and offsets over horst and tilted

faultblocks. Lacustrine shale source. Half-graben.Solimoes Cratonic. Penn. sandstone reservoirs.Cuyo U.Tr. non-marine sandstone and tuff + UJ-LK non-marine. Source?

Anticlinal structures. Oil/gas.Magallanes J-K sandstones (shoreface?). Source?San Jorge UK multiple lenticular sandstones. Traps include porosity pinchout in

tuffaceous sandstones.China Qaidam Olig-Ple. Continental sandstones. Jur source.

Ordos Mature. Tr-J fluv.-lacustrine Sandstones.Songliao Mid-J graben. 6km sediments, mainly non-marine. Several basinwide u/c’s.

MK non-marine source. LK reservoirs are multiple lacustrine-fluvsandstones. Horst-graben traps.

Tarim Jur lacustrine-fluvial sandstones. Low Hc richness.Russia West Siberian Cratonic, unaffected by compression or extension. Typical vertical structure

growth. Overlies Pz/Pt deformed belts. Initial Triassic graben subsidence.Never wholly marine. Wholly clastic. Coal-bearing – no significantcarbonate or evaporite. Traps formed by basement-controlled uplifts(dome-like anticlines along wide fault-bounded arches of early Jurassicelevation. Oil/gas mainly in Cret sandstones. Some control by basementtopography. U. Jur “Marine” hot shale source.

Vilyuy Late Perm-Trias gas basin; coal source. Cratonic.Africa, Middle East Illizi Cratonic. Oil mainly in Dev. Sandstones, less in Carb., in faulted anticlines.

Silurian source.Oman (Dhofar) Paleozoic including glacial sediments at base.

India Cambay Eocene lagoonal shale source. Eoc-Oli sandstone reservoirs (fluvio-deltaicinfill from north). Basinwide u/c at base; Miocene represents top of oilsystem. Complex domal anticlinal traps (no stratigraphic traps?).

Comments on candidate analogues

Extracting quantitative data at the play level frompublic-domain sources is challenging. Of thefollowing three examples, the Frio play of the USGulf Coast has already been used in the BasinAnalogue approach to resource estimation, above.

Pennsylvanian plays of the Cherokee PlatformProvince (Kansas) (R.R. Charpentier (USGS,National Assessment, 1995)); example of spectrumof trap types from Stratigraphic to Structural influvio-deltaic facies in a highly mature basin(200,000 wells, 269 fields >1 MMboe in a basinarea of 67,000 sq km). 163 oil and 11 NAGaccumulations (>1 MMBoe) are classified as



structural and combination (largest 500+MMboand 120+ Bscf), and 90 oil and 5 NAGaccumulations are classified as stratigraphic(largest 75 MMbo and 150+ Bcf). Thus there is asignificant bias towards the structural end of thespectrum. Net pay thickness averages 22m in thestructural play and 9.5m in the stratigraphic play.A possible analogue for Patchawarra plays in theCooper Basin.

Tertiary Oil and Gas Play, Uinta Basin, westernUSA (C.W. Spencer, USGS, National Assessment,1995): Fluvial and lacustrine reservoir faciescharged from a gas-prone coal/shale source(Mesaverde) as well as an oil-prone lacustrine shalesource (Green River); traps are mainlystratigraphic, with intraformational shale seals;some traps are combination structural-stratigraphicincluding the large Red Wash field (175 MMbo,373 Bcf). The largest field (presumed structural)has 260 MMbo and 378 Bcfg.

Of additional interest is the fact that conventionalplays grade into tight gas reservoirs in the deeperparts of the basin, where they have been the subjectof some of the more detailed studies that have beencarried out on these unconventional reservoirs.

Frio Updip Fluvial Gas & Oil Play (USGSNational Assessment, 1995): our previous report(Griffiths, 1997) referred to the Oligocene FrioFormation plays of the southern USA as a potentialanalogue for sandstone reservoirs in the CooperBasin; the mid- and down-dip plays in the Frio areless relevant as the facies are marginal to fullymarine downdip and the traps include salt-relatedtypes. In the updip play the reservoirs are fluvialand traps are both structural (faults, faultedanticlines, simple anticlines) and stratigraphic(channel sandstone enclosed in mudstones);exploration for undiscovered resources is expectedto focus on stratigraphic traps. Migration was upfault planes (though faults can also be sealing)from an unknown but probably Tertiary sourcerock. There are 60 gas accumulations with mediansize 11 Bcfg, and 32 oil accumulations with mediansize of 3 MMbo.

[Note: 1 Bcf = 0.02832 x109m3 1 MMbo = 0.1553 x109m3 ]



APPENDIX III: Towards a play analysis ofthe Cooper Basin

There is little discussion in the literature of the playconcept as applied to the Cooper Basin; hence thedifficulty in performing resource estimation studiesin terms of exploration plays. The followingsummary is probably highly over-simplified.

For all plays:

The petroleum charge system is assumed to exist,to work, and to be available to all proven andpotential plays.

Reservoirs are generally multiple in any one“field”; the field is thus a geographical coincidenceof sufficient accumulations sufficiently closetogether that they make an economicallyexploitable whole. This generalisation appliesparticularly to the coal-bearing Patchawarra andToolachee formations; less so to the Merrimeliaand other formations. The individual sands in anyone field may belong to more than one formation.Reservoir sands away from such “fields” may behydrocarbon-charged, but (a) invisible seismicallyand (b) individually too small to be economic.

Traps form a continuum from stratigraphic tostructural, few traps being either purelystratigraphic or purely structural (J. Morton, pers.comm.). Known traps are predominantlyassociated geographically with the major positivestructural features in the basin – possibly a result ofexploration having been concentrated around thosefeatures. Stratigraphic elements typically includepinchout, and onlap on to pre-existing structuralfeatures. Structural elements include four-way dipclosures, and sealing faults.

Seals are most commonly intraformational;regional seals exist but are not always effective.

Glacial plays: Merrimelia Formation

The Merrimelia Fm is very immature forexploration. Having for a long time been writtenoff as economic basement, good quality, productivereservoir has been found in two fields, incompletely different facies in each (one aeolian andone channel-sand facies). Further exploration ishigh risk (because of the few penetrations andhence poor understanding of facies distribution) butpotentially high reward.

Braidplain plays: Tirrawarra Formation

The Tirrawarra Formation, being a single sheetsand, and also being the main oil reservoir unit, is

probably better understood and more mature forexploration than other plays. Stratigraphic trapsare less likely, and there are likely to be fewsurprises, making this a low risk but low rewardplay.

Multistorey channel and point-bar plays:Patchawarra Formation, Epsilon Formation,Daralingie Formation, Toolachee Formation

This is the single most productive play in the basin,but also the most complex. Fields typically have adozen or more stacked sandstones, individuallyoften only a few metres thick. Correlation is amajor problem and sand development is poorlypredictable, although there is some evidence thatchannel sands may tend to stack vertically as aresult of confinement between “walls” of raisedpeat bog.

Shoreface sandstone play: Epsilon Formation

Although the Epsilon Formation lacks coals, thefluvio-deltaic facies within the formation hassimilar characteristics to the PatchawarraFormation as described above. The lacustrineshoreface facies could well have better potential interms of predictability; a modelling study is at theproposal stage. The Epsilon has had a significantnumber of discoveries, and improvements inpredicting sand fairways could reduce theexploration risk; this is therefore a moderate risk,moderate reward play.

Potential plays:

Several authors have commented on the scope fordiscoveries in as yet untested plays. Most of theideas listed below are not original but can be foundamong the following papers: Stanmore (1989),Apak and others (1993-5), Hollingsworth (1989),Yew & Mills (1989).

Conventional plays:

Lowside fault traps; applies to all productiveformations. Risk is on sealing properties of faults,as well as on distribution of faults (which howeverare probably quite widespread).

Unconformity-related traps: Sub-Daralingieunconformity, intra-Patchawarra unconformities(difficult to resolve because of the very lowangularity).

Stratigraphic traps at the basin margin and alongflanks of individual troughs.



Facies change (e.g. channels) unrelated tostructural highs. (The large Candeias field in theReconcavo Basin of Brazil is a stratigraphic trap inan essentially synclinal setting.)

Pinchouts at various stratigraphic levels alongintrabasinal highs and basin margins.

Oil legs downdip of proven gas reservoirs.

General comments on stratigraphic traps:

There is a general tendency worldwide for theproportion of fields with stratigraphic traps toincrease with increasing exploration maturity.Stratigraphic traps may be important topredominant in some fluvio-deltaic and fluvio-lacustrine settings (Uinta and Piceance basins,USA); the Gulf Coast Frio play used above as abasin analogue is a counter-example, having fewerthan 1% stratigraphic traps (syn-sedimentary faultsare the predominant trapping mechanism).

Unconventional plays:

All of the following unconventional gas play typeslisted by Dyman et al (1997) could apply within theCooper Basin, and could help to explain the“disappearance” of the large volumes of gasestimated to have been generated. SEEAPPENDIX IV.

1. Coalbed methane (Patchawarra andToolachee formations)

2. “Continuous-type” (basin-centred) gas3. Tight gas reservoirs4. Deep geopressured gas5. Black shale gas (Appalachian-type)

Although large volumes of gas could be accountedfor in various combinations of the above settings,their economic value is less certain.



APPENDIX IV: Assessment ofunconventional gas resources in the CooperBasin

Introduction

Gas resources described as “unconventional”include the following different but related types, allof which may be present in the Cooper Basin ofSouth Australia (CB-SA):

• “Tight” gas accumulations may includeconventionally trapped gas (as well as“continuous-type” pools – see below) in deepreservoirs of very low (e.g. < 0.1 mD)permeability.

• Coalbed methane (CBM). We have not seenany discussion of CBM as a potential resourcein the Cooper Basin and we have not attemptedto make a separate estimate of its potential inthis study, but the considerable volumes ofcoal in the Patchawarra and other formationssuggest the existence of some potential.

• Continuous-type gas accumulations, alsoknown as basin-centred. In this type, thetrapping mechanism is anomalous (andgenerally poorly understood) and the gasoccurs downdip of water-saturated rock andhence (counter-intuitively) in basinal lows. Inthis type of accumulation the deeper parts ofthe basin act as a relatively closed system suchthat the existence of major accumulations isless sensitive to the relative timing ofgeneration and trap formation than is the casefor conventionally trapped reserves (Law et al1986, Price 1997).

Unconventional gas resources have been thesubject of an increasing level of study in recentyears, almost exclusively in the United States.Some key references can be found in compilationsof papers by Spencer & Mast (1986), and Dyman,Rice & Westcott (1997). US unconventional gasresources were recently discussed in a series ofarticles in the Oil & Gas Journal by Kuuskraa andothers (1996, 1998). Unconventional gas playswere included in the 1995 National Assessment ofUnited States Oil and Gas Resources (USGSDigital Data Series nos 30, 35, 36).

In Canada, the Elmworth field in Alberta isdocumented in a collection of papers edited byMasters (1984).

Case histories outside North America are much lessnumerous. Law et al (1996) reported a “verylarge” (but unquantified) basin-centred gasaccumulation in Permian orogenic flysch and

molasse in the Pre-Ural sub-basin of the Timan-Pechora Basin in northern Russia. Law et al (1998)postulated another very large (35,000 km2) basin-centred accumulation in thick Carboniferous stratain the Dnieper-Donets Basin of the Ukraine. In-place resources could be in excess of 100 Tcf (2800x109m3 ).

Deep gas in low permeability reservoirs is alreadyin production to a limited extent in the CooperBasin, and Crosby et al (1995) made a comparisonwith several better studied examples in the U.S.A.,arriving at a positive outlook for tight gas in theCooper Basin. Rapid improvements in techniquessuch as fracture identification in advance ofdrilling, and in reservoir fracturing techniques,have greatly enhanced the economic viability ofthese deposits over the last two decades. The PerthBasin has also seen some limited attempts atidentification of tight gas resources (Wilkinson,1998).

Procedure

Dolton & Crovelli (1997) reviewed the followingsix assessment methodologies which they regardedas appropriate for deep natural gas resources:

1. Deposit simulation2. Reservoir performance3. Analogy4. Discovery process and finding rate models5. Mass balance models6. Areal and volumetric yield determinations

Of these, deposit simulation and reservoirperformance are largely ruled out in the case of theCooper Basin by lack of sufficient engineering andproduction data (though we refer below to theresults from Big Lake reported by Crosby et al,1995). Discovery process and finding rate modelsare difficult to use in the absence to date of anydeliberate exploration for unconventional gas in theCooper Basin. Mass balance has already beenconsidered in our earlier study, and underpins thegenerally accepted view that the Cooper Basin hasbeen flooded with hydrocarbons and thathydrocarbon charge is therefore not an issue. Weare therefore left with a combination of analogyand area/volume yields, and these methods formthe basis of what follows.

Analogues

Although continuous-type gas deposits typicallycut across lithostratigraphic and structuralboundaries, depositional environment remains animportant criterion, as the fracture geometries (bothnatural and induced) that are necessary forsuccessful production depend on nature and



continuity of sand-bodies. Crosby et al (1995)therefore selected the Lower Travis PeakFormation of East Texas/Louisiana and the FrontierFormation of the Green River Basin as analoguesfor the Tirrawarra and Patchawarra formations ofthe Cooper Basin, respectively. These examplesalso meet further criteria such as reservoir depthand pressure, and existence of fractures. There are,however, several other examples from non-marinedeposits in the United States, and these are drawnupon in the following list, in which we aim toderive a range of figures for the possible yield perunit area:

Greater Green River area, western USA

This area, comprising the Green River, Uinta andPiceance basins, has the greatest volume of tightsandstone gas in the United States and is a majorproducing area. The principal producingsandstones are non-marine, fluvial channel-fill andpoint-bar sandstones of Cretaceous-Tertiary age,although producing formations in the Uinta Basinrange in age all the way down to Cambrian. Theytherefore make a fair analogue for the CB-SA,except that basin-forming processes and thermalhistory were probably quite different.

Satriana (1980) quoted estimates of hydrocarbonrichness by area, as follows:

Basin Richness(109m3/km2)

Richness(Bcf/km2)

Green River Basin,Wyoming

0.14-1.6 5-55

Piceance Basin,Colorado

1.6-2.7 55-95

Uinta Basin, Utah 2.7-3.7 95-130

Law et al (1989) (quoted in Dyman et al 1997)estimated the in-place gas reserves of only thecoarse-grained rocks in the Greater Green RiverBasin as lying between 3,600 and 6,800 Tcf (i.e.the total including shale-gas could be higher).Using 51,000 km2 (Law et al 1986) as the totalarea, this converts to a richness figure forunconventional gas between 70 and 133 Bcf perkm2.

Cotton Valley and Travis Peak formations, Texas-Louisiana

Crosby et al used the Upper Jurassic Cotton ValleyFormation – a coastal plain deposit – as an analogyfor the McKee Formation of the Taranaki Basin,New Zealand. It might serve as an analogy for theToolachee Formation, though not for the morediscontinuous sands of the Patchawarra Formationin the Cooper Basin. The Travis Peak Formation

was selected as an analogue for the TirrawarraSandstone.

Finley (1986) gives some useful statistics for thesetwo formations, as follows:

The Cotton Valley tight gas play extends overabout 34,000 km2 in eastern Texas and adjacentparts of Louisiana. 12.8 Tcf is the estimated“maximum” (?P90) recoverable reserve. Meanpermeability is 0.042 mD, and porosity is 6-10%,exceptionally 18%. Wells typically yield 2-4 Bcfeach at rates of up to 2,500 Mcf/d after stimulation;some also yield up to 40 b/d condensate. Using12.8 Tcf as the only available reserves figure,hydrocarbon richness is estimated as 0.38 Bcf/km2.

The Travis Peak play extends over a similar area –33,000 km2. Environment is described is marine-influenced delta fringe. Mean permeability is0.026 mD; porosity is 2-9%. Reserves areestimated as 13.8-17.3 Tcf recoverable if 12-15%of the basin area is ultimately productive. Thisgives a richness figure of 0.42-0.52 Bcf/ km2 ofrecoverable gas.

Cleveland Formation, Anadarko Basin, southernUSA

Data are from Finley (1986) and Hentz (1994).

According to Hentz, 459 Bcf + 18.6 MMbo hasbeen produced from low-permeability (<0.1 mD)reservoirs from a 13,000 sq km area. Traps areconventional traps and the reservoir depositionalenvironment is fluvial-deltaic. There are 47 fieldsin the area of which 24 have produced >1 Bcf, 8>10 Bcf. (The three largest fields are 135, 99, and58 Bcf). Note that these figures are for producedgas; not in-place or ultimate recoverable. The totalproduction gives a minimum areal richness figureof 0.035 Bcf/km2.

From Finley’s data, mean permeability is 0.028mD. Mean post-stimulation flow rates were 218Mcf/d, with up to 5 b/d condensate. Finley gave noestimates of resources.

Elmworth and related gas fields, Alberta DeepBasin, Canada

Elmworth covers an area of 105 km x 48 km with250 recognised pools of commercially recoverablegas in 23 stratigraphic zones (Masters, 1984). Theentire Mesozoic section is saturated with gas,through a total column of 914 m. Rocks are water-saturated updip. The principal reservoir is theLower Cretaceous Mannville Sandstone, withinwhich the main reservoir facies is beach andshoreface sandstones. While low permeabilities



predominate, there are also belts of reservoir rockwith more normal porosity and permeability.

Elmworth has an estimated 17 Tcf of gas reserves+ 1 billion barrels of NGLs.

Total economic reserves of the Deep Basin may be45 Tcf (Masters, 1984); the area of the Deep Basinis 61,000 sq km, which gives a hydrocarbonrichness of 0.7 Bcf per sq km.

Dnepr-Donets Basin, Ukraine

Described by Law et al (1998) as extending over35,000 km2 of the Dnepr-Donets Basin (nearly halfthe total area of the basin), this accumulationremains rather hypothetical and has certainly notbeen delineated or described in any detail. Withoutdescribing their assessment methods, the authorsestimate the total in-place gas resource as in excessof 100 Tcf. As they draw attention to similaritieswith North American examples includingElmworth and the Anadarko Basin it is possiblethat their estimate is based on analogy rather thanon the intrinsic properties of the Dneptr-Donets

Basin itself. If taken at face value their estimateleads to a richness per unit area (for unconventionalgas only) of about 3 Bcf per km2 over the supposedarea of the accumulation, or 1.3 Bcf per km2 overthe entire area of the basin (about 75,000 km2).

Timan-Pechora Basin, northern Russia

Law et al (1996) postulated a “very large” basin-centered gas accumulation in Permian age flyschand molasse sediments in the Pre-Ural sub-basin ofthe Titman-Pechora Basin of northern Russia. Thegas-bearing Artinskian to Ufimian sandstones areup to 2,000 m thick, and comprise sandstone,siltstone, shale and coal (the source for the gas).Sandstones have porosities in the range 3-15%;permeability is less than 0.1 mD. The sands aregas-saturated, with little or no producible water,and are at high pressures; gradients are 0.5-0.6psi/foot. The top of the gas zone cuts acrossstructural and stratigraphic boundaries, as iscommonly the case in these unconventionaldeposits. However, the potential reserves of thisaccumulation have not so far been estimated.

Summary of hydrocarbon richness figures from analogue basins:

Basin/Play Author 109m3/km2 Bcf/km2 ResourceGreen River Basin Satriana 0.14-1.6 5-55 Assumed OGIPPiceance Basin Satriana 1.6-2.7 55-95 Assumed OGIPUinta Basin Satriana 1.6-3.7 55-130 Assumed OGIPGreater Green River Basin Law 2-3.7 70-130 OGIPCotton Valley Finley 0.01 0.38 ?P90 recoverableTravis Peak Finley 0.01-1.15 0.42-0.52 RecoverableCleveland Fm, Anadarko Basin Hentz 0.001 0.035 Cumulative prod.Alberta Deep Basin Masters 0.02 0.7 Recoverable (?P50)Dnepr-Donets Basin Law 0.04 1.3 OGIP

Consequences for the Cooper Basin

Applying the above considerations wouldsuggest that, given the 30,000 km2 area of theCooper basin, and a 0.1 to 1 x109 m3/km2

richness, the potential resource of the CooperBasin may be of the order of 3000 x109 m3 to30000 x109 m3. Given that Griffiths (1997)

estimated the Patchawarra Unit 4 coalpotential productivity as 10000 x109 m3, thissuggests that any Cooper Basin potential forunconventional gas resources is at the lowerend of the richness scale (around 0.1 to 0.3x109 m3/km3.



Unconventional Gas – REFERENCES

Crosby, D.G., Tamhane, D., Yang, Z., Khurana,A.K. & Kuuskraa, V.A. 1995. A review of theU.S. tight gas industry from the perspective ofselected Australian and New Zealand basins.APEA Journal 1995, 692-705.

Dolton, G.L. & Crovelli, R.A. 1997. Assessmentmethodology for deep natural gas resources. In:Dyman, T.S., Rice, D.D. & Westcott (eds) 1997.Geologic Controls of Deep Natural Gas Resourcesin the United States. U.S. Geol. Survey Bulletin2146-O, 233-239.

Dyman, T.S., Rice, D.D. & Westcott (eds) 1997.Geologic Controls of Deep Natural Gas Resourcesin the United States. U.S. Geol. Survey Bulletin2146.

Hentz, T.F. 1994. Sequence stratigraphy of theUpper Pennsylvanian Cleveland Formation; amajor tight-gas sandstone, western AnadarkoBasin, Texas Panhandle. AAPG Bulletin, 78 (4)569-595.

Hugman, R.H. 1988. Ultimate recovery analysisby formation and play for deep Anadarko Basinand estimation of undiscovered gas potential(Abstract). AAPG Bulletin, 72 (2), 199.

Kuuskraa, V.A., Hoak, T.E., Kuuskraa, J.A andHansen, J. 1996. Tight sands gain as U.S. gassource. Oil Gas Journal 94 (12), 102-107.

Kuuskraa, V.A., Schmoker, J.W. & Dyman, T.S.1998. Diverse gas plays lurk in gas resourcepyramid. Oil Gas Journal 96 (23), 123-130.

Law, B.E. et al. 1989. Estimates of gas resourcesin overpressured low-permeability Cretaceous andTertiary sandstone reservoirs, Greater Green RiverBasin, Wyoming, Colorado, and Utah. In: GasResources of Wyoming: Guidebook, 40 th WyomingGeological Association Field Conference, 36-62.

Law, B.E. et al. 1986. Geologic characterisation oflow-permeability gas reservoirs in selected wells,Greater Green River Basin, Wyoming, Coloradoand Utah. In: Spencer, C.W. & Mast, R.F. 1986.Geology of Tight Gas Reservoirs. AAPG Studiesin Geology 24, 253-269.

Law, B.E. et al. 1996. Basin-centered gasaccumulation in the Timan-Pechora Basin, Russia.In AAPG Annual Convention Abstracts (1996) p.81.

Law, B.E., Ulmishek, G.F.,. Clayton, J.F.,Kabyshev, B.P., Pashove, N.T. & Krivosheya, V.A.1998. Basin-centered gas evaluated in Dnieper-Donets basin, Donbas foldbelt, Ukraine. Oil GasJournal 96 (47), 74-78.

Masters, J.A.. (ed.) 1984. Elmworth – Case Studyof a Deep Basin Gas Field. AAPG Memoir 38, 316pp.

Masters, J.A.. (ed.) 1984. Lower Cretaceous Oiland Gas in Western Canada. In: Masters, J.A..(ed.) 1984. Elmworth – Case Study of a DeepBasin Gas Field. AAPG Memoir 38, 1-33.

Price, L.C. 1997. Origins, characteristics, evidencefor, and economic viabilities of conventional andunconventional gas resource bases. In: Dyman,T.S., Rice, D.D. & Westcott (eds) 1997. GeologicControls of Deep Natural Gas Resources in theUnited States. U.S. Geol. Survey Bulletin 2146-L,181-207.

Spencer, C.W. & Mast, R.F. 1986. Geology ofTight Gas Reservoirs. AAPG Studies in Geology24, 299 pp.

Wilkinson, R. 1998. Local explorers spearheadattempts to unlock “tight” gas in Perth Basinreservoirs. Petroleum Gazette (AustralianPetroleum Institute), 33 (2), 4-10.



Appendix V: Summary table of formation top depths, from PEPS database

Formation Topmin

Top max Top mean Top SD Basemin

Base max Basemean

Base SD

Nappamerri 1673 2576 2061 244 1683 2866 2205 307

Toolachee 1615 3202 2196 336 1668 3259 2264 328

Daralingie 1668 2828 2151 255 1680 2922 2183 266

Epsilon 1673 3259 2313 346 1686 3277 2365 348

Patchawarra 1210 3297 2320 374 1317 3733 2486 454

Tirrawarra 1317 3733 2793 452 1372 3798 2828 452

Merrimelia 1729 3798 2767 449 1737 3853 2837 452

Data from fields only, and from Exploration wells only (i.e. probably mainly discovery wells)

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