Visitors Welcome!

New Venue:
NCPGG Lecture Theatre
Level 1, 30-32 Stirling Street, Thebarton
Thebarton Campus, The University of Adelaide

NB - This timetable is correct as of June, 2000 but rescheduling may occur.
Visitors are advised to confirm this timetable closer to the date of the presentation.

Dr Ghazi Kraishan (tel 08 8303 3502 or email gkraishan@ncpgg.adelaide.edu.au) or
Maureen Sutton    (tel 08 8303 4299 or email msutton@ncpgg.adelaide.edu.au)

  Tuesday, January 25, 1-00pm

  Dr. R. Winn - Department of Geosciences, University of Papua New Guinea

  Lower Miocene Nukhul Formation, Gebel el Zeit, Egypt:
  model for structural control on early syn-rift reservoirs, Gulf of Suez

         The lower Miocene Nukhul Formation is the basal syn-rift unit across most
  of the Gulf of Suez basin, where the unit is an important reservoir. The
  Nukhul Formation at Gebel el Zeit, Egypt, at the southern end of the Gulf
  of Suez, dips 8-15° less than underlying pre-rift strata. The discordance
  and presence of basement clasts in the Nukhul indicate that significant
  rotation, extension, and tilting preceded rift subsidence of the Gebel el
  Zeit fault block.
         The Nukhul at Gebel el Zeit is up to 75 m thick in outcrop, and consists
  of lower sandstone and upper carbonate units. The change in facies
  indicates water deepening during sedimentation, probably due to tectonic
  subsidence. The formation is observed to vary considerably along strike due
  to syn-depositional differential movement of small fault-bounded blocks.
  The lower clastic unit at South Gebel el Zeit contains poorly sorted,
  conglomeratic, marly sandstone that commonly displays grading and Bouma
  sequences. Beds were deposited by sediment gravity flows below storm base.
  Thicker intervals filled small, structurally controlled, submarine gullies
  that funneled sand and gravel southwestward to a half graben, where the
  Nukhul significantly thickens. In contrast, a correlative, thin, basal
  conglomeratic unit in North Gebel el Zeit was deposited in a shallow marine
         The upper carbonate unit consists of bioclast, peloid, and intraclast
  packstone, wackestone, and grainstone with minor floatstone, rudstone, and
  coral-algal boundstone. Carbonate strata were deposited variously in deep
  marine, low-energy peritidal and subtidal, and reefal environments.
  Considerable lithologic and thickness variability also is related to
  differential movement of local fault blocks. Deeper submerged blocks were
  the site of carbonate resedimentation or deeper shelf deposition. Reefs and
  shallow-marine bioclast shoals formed on higher submerged blocks. Nukhul
  strata demonstrate that syn-rift reservoir prediction in the Gulf of Suez,
  Red Sea, and presumably many other rifts requires mapping of bounding
  faults and syn-rift cross faults and requires fault block by fault block
  facies analysis.

         Robert Winn currently is Associate Professor and Head of the Department of
  Geosciences at the University of Papua New Guinea, where he lectures in
  stratigraphy, sedimentology, and petroleum geology. He received a Ph.D.
  from the University of Wisconsin-Madison in 1975. Subsequently, he held a
  post-doctoral research position at the University of Wisconsin and taught
  for one year at the University of California-Berkeley before joining the
  research lab of Marathon Oil in 1977. Dr. Winn moved to the University of
  Papua New Guinea in 1994. At UPNG he had been Associate Dean of Science and
  Chair of the University Research Committee before becoming Head of
  Department in 1996.
         Prof. Winn's major interests are in clastic sedimentology and sequence
  stratigraphy. His recent work has been on sedimentation in the Gulf of Suez
  rift basin, sequence stratigraphy of the Toro-Imburu reservoir section in
  PNG, Quaternary shelf-edge deltas in the U.S Gulf coast, and Neogene
  tectonic evolution of the Papuan orogen.


  Tuesday, February 1, 1-00pm

  Mrs. Evelina Paraschivoiu  - PhD Candidate, NCPGG

 The Use Of Three-Dimensional Nested Forward Stratigraphic Simulations
 To Provide Variable-Scale Heterogeneity Models

  SEDSIM is a 3D hydraulic forward modelling package that simulates the
  transport, deposition and erosion of sediment on a bathymetric surface. The
  algorithm employed is based on numerical approximations to fluid flow
  equations. The model generates a 3D distribution of uncompacted sediments
  with up to six different grain sizes. The stratal patterns and lithofacies
  continuity within the simulated sedimentary bodies are influenced by the
  interaction of different combinations of input parameters, such as sediment
  supply, sea level changes, tectonic subsidence, and wave action. The
  simulation output, at each grid node, consists of a succession of equal time
  layers each characterised by the thickness of each of the constituent grain
  A series of test simulations were carried out on a 16 km x 20 km area of
  lower shore-face sands from the Browse Basin, Northwest Shelf of Australia.
  The experimental series involved grid spacings at 2000 m, and 1000 m. The
  temporal resolution for the simulation was varied in the range 2, 5, and 10
  ka. Three-dimensional forward stratigraphic simulation was shown to provide
  an effective multi-scalable deterministic framework on which to base a
  quantitative heterogeneity model.
  Translation of the simulated grain-size to porosity, permeability and
  capillary pressure has been shown by other workers to be possible.
  Subsequent compaction and diagenesis can be estimated for the
  computer-generated sediment bodies. Spatial and temporal heterogeneity was
  shown to be comparable throughout upscaling, and examination of the forward
  modelling results enable a decision to be made about the type of sand body
  correlation that is appropriate in any particular depositional environment.
  Spatial variance from the highest resolution simulation, supplemented by
  wireline and plug data, may be used to carry out multiple conditional
  simulations of the upscaled forward modelling cells to provide some measure
  of the uncertainty in the otherwise deterministic simulator block values.

  A work flow is suggested whereby stratigraphic forward modelling may provide
  a practical route not only to the quantifying of a conceptual reservoir
  depositional model, but to the upscaling of flow units for reservoir


Tuesday, February 8, 1-00pm

Ms. Rosalie Pollock - PhD Candidate, NCPGG

The influence of Tertiary tectonic movements on the
 stratal architecture, maturation and migration of hydrocarbons
 in the Gambier Sub-basin, Otway Basin system, southern Australia

  Exploration for oil and gas, especially within frontier basins, is a
  high-risk venture, generally due to the lack of well control and detailed
  knowledge of basin history.  Various methods are employed to reduce this
  risk, including application of predictive sequence stratigraphic studies
  integrated with biostratigraphy and seismic interpretation.

  Sequence stratigraphy is an important technique that predicts the location
  of facies, allowing the position of potential sources of oil and gas to be
  identified.  The Gambier Sub-basin is an example of a frontier basin in
  southern Australia with only a few small developing gas fields.  There is
  good seismic coverage and limited well coverage.  A regional sequence
  stratigraphic study is needed to investigate the tectonic movements in the
  Tertiary that have affected basin architecture and altered maturation and
  migration pathways.

  To date, hydrocarbon exploration targeting reservoirs in the Cretaceous and
  lower Tertiary, southwest of the Tartwaup Fault has proved futile.  There
  are no wells producing hydrocarbons in the southern part of the Gambier
  Sub-basin.  Caroline 1 is a high quality carbon dioxide producer, but no
  hydrocarbons flow from this well.

  The purpose of this study is to develop a sequence stratigraphic framework
  for the Gambier Sub-basin which will enable prediction of reservoir and
  seal facies.  This study will analyse the timing and degree of faulting
  within a sequence stratigraphic and chronostratigraphic framework,
  integrating seismic, well logs, biostratigraphy, outcrops, and core and
  cuttings descriptions, to determine the localities of kitchens which may be
  linked to migration pathways and potential stratigraphic and structural traps.


Friday, March 3, 1-00pm

Dr. Brian Evans - Assoc. Prof in Geophysics, Curtin University

Past and Future Research Trends in Geophysical Technology

The past thrust of seismic research has been concentrated on multiple
prediction and fracture detection under Australian geological conditions.
Multiple R&D has evolved to where it is being used on 2-D seismic data, but
it is now being adapted for 3-D applications. Allied with this, the need to
resolve reflections beneath high velocity layers and scatterers has been a
consistent problem in the Perth Basin and offshore NWS, and with which some
progress is being made.

 Sand box modelling, a domain of the structural geologist, has also been an
area of interest for further development in terms of fluid flow modelling
concepts and time lapse 3-D surveying.

 This seminar will present work being done in these areas and the direction
of future trends. It will suggest that there are evolving 3-D seismic
methods in reservoir fluid flow simulation which will underpin some of the
future research areas of C02 sequestration, seal integrity and reservoir

 The seminar suggests areas for future research collaboration.

Tuesday, March 7, 1-00pm

Dr. Dennis Cooke - Santos Ltd.

B Field, Offshore NW Java
A Case History of Multi-Disciplinary Integration

  This is a SPE talk that describes the history of a MDT (Multi-Disciplinary
  Team) that integrated 3D seismic, reservoir simulation, horizontal drilling
  and NMR logging.  In this history, the MDT was formed because of concerns that a
  offshore development platform currently under construction would not find the
  expected oil reserves.  The MDT started by building a reservoir simulation
  based on old 2D seismic mapping, and this simulation did not show any problems.
  However, this simulation had contradictions concerning the structure maps and
  fluid contacts.  To address these contradictions, a 3D survey was shot.
  Due to obstructions and the water depth, the 3D survey had to be collected using 2
  component ocean bottom sensors. 3D acquisition started just 8 months before
  the planned start of drilling.  To accelerate the entire process, seismic
  processing was done in the field as the data were collected.  Interpretation on a
  preliminary seismic data volume was finished before the last shot point was
  acquired in the field.  The new 3D maps showed that the original target
  reservoir did not contain the required reserves, but a shallower reservoir
  might contain as much oil as the original, deeper target.  An updated simulation
  indicated that the new shallower horizon was an economic target.
  Unfortunately, the platform jacket had been set by this time (but the wells had not been
  drilled), and its location was not optimal for the new target reservoir.  This
  led to one of the wells being a long reach horizontal well targeting a very
  thin (<15 ft) reservoir.  There were also critical questions about the water
  saturation of this new reservoir that were address with NRM logging.

  Dennis Cooke has a B.A. in Geology from the University of Colorado and a Ph.D.
  in Geophysics from the Colorado School of Mines.  He has worked in seismic
  acquisition, seismic processing, research and seismic interpretation
  applied to exploration and development.  His geographic experience includes work in
  some of the Rocky Mountain basins, offshore California, Indonesia, Alaska with short
  special application projects in the North Sea, China and Gulf of Mexico.  His
  interests include seismic inversion, reservoir characterisation,  seismic
  attributes, AVO and 3D interpretation tools.  He is currently Chief Geophysicist
  Corporate for Santos.


Tuesday, March 21, 1-00pm

Dr. P.R. Tingate - NCPGG


  The study was funded by the Petroleum Group in Primary Industries and
  Resources South Australia (PIRSA) in order to ascertain more information
  about the petroleum generation history of the eastern Officer Basin. The
  boreholes analysed included Manya-2, -5 & -6; SMD5001 and Giles-1.

  The samples analysed come from formations Proterozoic to Mesozoic in age.
  Within the basin succession there are several major unconformities
  representing uncertain amounts of erosion.   They occur between 560 and 540
  Ma (Petermann Ranges Orogeny), approximately 500 - 490 Ma (Delamerian
  Orogeny), 375 - 290 (Alice Springs Orogeny), 260 - 150 Ma, and 95 - 35 Ma.
  Only relatively minor erosion has probably occurred since the development
  of late Eocene - Early Miocene (~ 35 Ma) Cordillo surface.

  All Proterozoic and Cambrian samples show evidence of cooling from
  temperatures >=100°C during the Alice Springs Orogeny.  The AFTA data does
  not constrain palaeotemperatures from earlier events.

  All samples appear to have cooled from elevated temperatures of 90- 100°C
  prior to cooling between 110 and 70 Ma with most having cooled from
  temperatures ~ 25°C higher during the last 50 Ma.

  Elevated temperatures associated with the last two events are probably
  related to increased depth of burial but may also be associated with
  increased temperatures caused by aquifers with heated water.

  The Proterozoic and Cambrian samples analysed were within and possibly
  passed through the oil window prior to cooling during the Alice Springs
  Orogeny between 360 and 300 Ma. The basal part of the 500m thick section of
   Permian and Mesozoic section in Manya-2 appears to have entered the 'early
  mature' part of the oil window prior to cooling between 110 and 70 Ma.


Tuesday, March 28, 1-00pm

Mr. Trevor Dhu - PhD Candidate, NCPGG

The Use of Fractal Dimension for Textural-Based Enhancement of Aeromagnetic Data

  Textural-based processing of airborne magnetic data is becoming a recognised
  tool of image enhancement.  Texture is a relatively subjective property,
  however with respect to magnetic data it can be thought of as the shape and
  distribution of anomalies within a region.  Fractal dimension (FD) provides
  a measure of texture that can resolve subtle textural contrasts as well as
  edge features that are otherwise difficult to discern.

  The variation method is a robust technique for estimating FD, capable of
  enhancing both linear and sinusoidal ramp anomalies contained within
  synthetic datasets.  The variation method clearly resolves these features
  even in the presence of Gaussian noise.  The results demonstrate that
  smaller window sizes will more effectively discriminate and enhance edges.

  Application of the variation method on the Ghanzi Chobe aeromagnetic dataset
  highlighted structural features that are not resolved in the greyscale total
  magnetic intensity image.  Comparison of the variation method with
  conventional, derivative-based enhancements, suggests that the variation
  method enhances similar structural trends but with greater clarity.  It also
  enhances structural features that are not revealed by horizontal and
  vertical derivative images.  The results suggest that this style of
  enhancement will be most useful for enhancing subtle, high frequency
  features in regions of little magnetic relief.

Monday, April 10, 1-00pm

Mr. Scott Reynolds -  PhD Candidate, NCPGG

The Australian Stress Field

  Since the compilation of the World Stress Map in 1992, the number of
  reliable (A-C quality ranked) in situ stress measurement has increased
  substantially. Included in the new data is a detailed stress analyse of the
  Bowen, Sydney and Perth Basins. The Bowen and Perth Basins show a consistent
  regional maximum horizontal stress trend while the Sydney Basin shows no
  regional trend.

  Two techniques have been used to highlight the regional in situ stress
  trends throughout Australia: the definition of stress provinces and stress
  trajectory mapping. These two different statistical approaches have produced
  consistent results which emphasize the regional trends throughout Australia.

  Unlike most continental areas the stress orientations throughout Australia
  do not parallel the direction of plate motion. New plate boundary force
  modelling as been undertaken on the updated regional trends using a new
  statistical approach. This has resulted in an improved fit to the observed
  stress field and has further confirmed that the regional stress pattern is
  consistent with control by plate boundary forces.

Tuesday. April 18, 1-00pm

Dr. Abbas Khaksar - Postdoctoral fellow-Petrophysics, NCPGG

Seismic Signature of Partial Saturation,
Link Between Acoustic Properties and Capillary Pressure Curves??

  The influence of saturation by water, gas, and mixtures thereof on
  velocities and elastic moduli of reservoir rocks is of considerable
  interest in exploration geophysics. However, very few studies have
  investigated the relationship between acoustic velocities and partial fluid
  saturation in sandstones under in situ and varying stress conditions. This
  presentation examines compressional and shear velocities (Vp and Vs)
  obtained from a systematic laboratory measurement made on a set of Cooper
  Basin sandstone cores as a function of water saturation (Sw) and effective

  Petrographic information, capillary pressure curves, and acoustic data were
  incorporated into a simple pore geometry model to interpret the
  velocity-saturation relationship and stress sensitivity under partially
  saturated conditions for the studied samples.  The steady decrease of Vp as
  saturation decreases over the range from high to moderate Sw suggests a
  simultaneous drainage of water from pores with a variety of high to
  moderate aspect ratios, while crack-like (low aspect ratio) pores retain
  water. Closure and degree of saturation of the low aspect ratio pores
  controls the velocity-stress and velocity-saturation relationships at low
  saturation and stress conditions. This observation confirmed that
  saturation heterogeneity results in velocity changes across a large
  saturation range, distinctly different from the case of uniform saturation
  (Biot-Gassmann model) where there is only a large change in velocity close
  to the point of full water saturation.

  The magnitude of changes in velocities with saturation observed for samples
  used here appears not to be practically significant (around 2% for Vp).
  This suggests that, at ultrasonic frequency, the degree of saturation can
  not reliably be inferred from Vp or Vs only. The Vp/Vs ratio, however,
  shows a noticeable decrease in magnitude over the saturation range from
  high to low saturation near irreducible saturation.  Simple comparison
  between the capillary pressure data and the shape of the Vp/Vs-saturation
  curve is promising. If Vp/Vs-saturation relationship observed at ultrasonic
  frequency exist at sonic log and seismic frequencies, then velocity data in
  conjunction with lithological information could determine the saturation
  status of hydrocarbon reservoir rocks. Further investigation is needed to
  confirm this observation at log and seismic frequencies, and for other rock


Thursday, May 4, 1-00pm

Dr. Richard Jones - Postdoctoral Fellow, NCPGG

Integrated Hydrocarbon Seal Evaluation in the Penola Trough, Otway Basin

  Seals are one of the main components of the petroleum system yet their
  evaluation has received surprisingly little attention in terms of
  integrated risk assessment. This paper presents an overview of fault seal
  evaluation strategies and emphasises the need for an integrated,
  multi-disciplinary approach for robust fault seal evaluation so to
  correctly understand seal risk. The region of study is the Penola Trough,
  Otway Basin where recent improvements in seismic quality, stratigraphic
  modeling and additional well control have greatly enhanced regional

  Four fault seal deformation mechanisms have been identified in Pretty Hill
  siliciclastic strata. These are phyllosilicate smear, phyllosilicate
  framework, cataclasis and cementation. Each deformation mechanism is able
  to support significant hydrocarbon column heights yet failure to accurately
  determine seal capacity of likely fault plane seal will lead to inaccurate
  trap integrity and reserves estimation. The impact of failure to accurately
  determine complex fault zone architecture on fault seal prediction is also

  Fault geometric characteristics are fractal and can, therefore, be
  described by power-law functions. Otway Basin seismic-scale data and the
  application of fractal fault characterisation to seal evaluation are

  The likelihood of structural permeability networks and possibility of fault
  seal failure within the in-situ stress field is evaluated. The integration
  seismic-scale fault geometry with in-situ stress data has resulted in the
  development of a new, rapid assessment fault seal risking tool (F.A.S.T -
  Fault Analysis Seal Technology) that maps relative probability of seal
  failure along the seismic fault trace. This tool represents a significant
  advancement in first-phase fault seal evaluation techniques.


Tuesday, May 16, 1-00pm

Dr. Tony Hill - PIRSA

National geoscience Mapping Accord (NGMA)
Cooper and Eromanga Basins Project       - Results and conclusions

  The NGMA project is a joint investigation being undertaken by agencies of
  the Queensland, South Australia, New South Wales, Northern Territory and
  Commonwealth governments.

  Its aim is to develop a quantitative petroleum generation model for the
  Cooper and Eromanga Basins by delineating the basin fill, thermal history
  and generation potential of key stratigraphic intervals in these basins.

  The four year project, due for completion in June 2000 has already produced
  a number of major products, including regional seismic and isopach maps for
  major horizons, an oil and source rock database and a thermal and burial
  history model of the basins.

  Tuesday, May 30, 1-00pm

  Mr. Tom Kivior - PhD Candidate, NCPGG

  Late Jurassic and Cretaceous Seals of the Vulcan Sub-Basin


  The Vulcan Sub-Basin contains several structural provinces containing major
  petroleum fields. Paleo-oil columns found within the Vulcan Sub-Basin
  suggest trap breach either via top-seal or fault leakage. This paper
  investigates the top seal leakage aspect. The regional extent, lithological
  description and sealing potential of Cretaceous sediments are qualified for
  the first time on a regional scale.

  Wireline logs correlations, based on biostratigraphic parameters, have
  been used to divide the Late Jurassic to Cretaceous sediments into four
  time continuous intervals. Results suggest that each of the four intervals
  defined is significant as a seal in different structural provinces of the
  Vulcan Sub-Basin.

  X-ray diffraction data and lithological descriptions of the Cretaceous
  intervals, suggest that the sealing lithologies are mainly calcareous
  shales and marls. Mercury injection capillary pressures tests, performed on
  mud chips and cores were used to determine seal capacity. Capillary
  pressure results suggest hydrocarbon column heights of up to one hundred
  meters are supportable by the calcareous sediments of the youngest interval
  identified in the Cretaceous.

Tuesday, June 20, 1-00pm

Mr. Pradipta Das - PhD Candidate, NCPGG

Influence of regional tectonics on the structural style and stratigraphy of
the SE Bass Basin: Some new observations


  Seismic, wireline and palynological data have been utilised to divide the
  sedimentary package in the southeastern Bass Basin into three
  mega-sequences: the pre-rift, syn-rift and post-rift. The major erosional
  unconformity seen on seismic data near Durroon-1 within the Early
  Cenomanian has been interpreted from the overall seismic reflection
  geometry and internal seismic facies characteristics both above and below
  it, to be the rift-onset unconformity. This unconformity marks the onset of
  the Tasman Sea rifting phase (dated 96 Ma - A. distocarinatus zone). This
  major tectonic event may have been synchronous with the initiation of
  sea-floor spreading in the Southern Ocean.

  The structural style in the southeastern Bass Basin (Durroon Basin) is
  characterised by large, domino-style, tilted basement fault blocks. Fault
  throws are in the order of 4 - 5 Km and occur along rotational normal
  faults. This is in complete contrast to the structural style in the
  adjacent Bass Basin to the west and northwest. There the structural style
  is dominated by regional subsidence and syn-sedimentary faulting along both
  planar and listric faults with much lesser throw.The development of
  accommodation space in the NW area appears to be more due to sedimentary
  loading in contrast to the SE area where the predominant influence is due
  to tectonic subsidence.

  The structural style in the Durroon Basin has been shaped through three
  major extensional phases that are reflected in different fault trends. The
  initial response to extensional forces was the development of discrete
  fault segments across the basin. The present day fault pattern subsequently
  developed through progressive propagation and linkages of the initial fault
  segments. The obliquity of Tasman rifting had a profound influence on the
  structural development. The offshore extension of the NE-trending Arthur
  Lineament probably acted as a buttress to limit the tensional stresses,
  resulting in the Late Cretaceous history in the Bass and Durroon basins
  being very different. However, from the Early Tertiary, the two basins
  became linked.

Tuesday, June 27, 1-00pm

Mr. Xinke Yu - Ph.D. Candidate, Department of Geology and Geophysics,
The University of Adelaide

A New Approach to the Estimation of Mixing Ratios in Reservoirs
Containing Multiple Oil Charges


A mathematical model based on a comprehensive mass balance of light and
  heavy hydrocarbon components and inspired by the work of Alexander et al.
  (1996) has been devised in an attempt to better quantify the mixing ratios
  of discrete oils in a given reservoir. A simplified two-source model is
  discussed here using as examples "pure" Cooper and "pure" Eromanga oils,
  and the full spectrum of mixing ratios represented by the 72 oil and
  condensate samples analysed in this study.

  For an oil pool of multiple origins (n sources each containing m components
  or groups of components), the weighted average value (Mj) of a certain
  chemical property (e.g. maturity; isotopic composition) can be calculated
  according to the general formula (1) below. Taking into account the
  observed variations in the chemical composition and maturity of Cooper- and
  Eromanga-derived crudes (the former are generally more mature and contain
  more gasoline-range hydrocarbons), the theoretical model can be adapted to
  a dual source scenario. Thus, for example, the maturities of the light (ML)
  and the heavy (MH) fractions of the composite oil can be calculated using
  the equations (2) and (3) below.

          Mj = Mij (xij yi/xj) where xj = xij yi; i = 1,2,3...n; j= 1,2,3...m; and m ³ n....(1)
          ML = MOL ´ POL PO / (POL PO + PYL PY) + MYL ´ PYL PY / (POL PO + PYL PY).....(2)
          MH = MOH ´ POH PO / (POH PO + PYH PY)] + MYH ´ PYH PY / (POH PO + PYH PY)..(3)
          Mij     = value of a certain property of the jth component in the ith oil source,
          xij     = portion of the jth component in the ith oil source,
          yi      = portion of oil from the ith source,
          xj      = portion of the jth component,
          ML and MH       = maturity of the light- and heavy-end hydrocarbons in the mixture,
          PY and PO       = portion of hydrocarbons sourced from the younger and the older rocks,
          POL and POH     = portion of light- and heavy-end hydrocarbons from the older rock,
          PYL and PYH     = portion of light- and heavy-end hydrocarbons from the younger rock,
          MOL and MOH     = maturity of light- and heavy-end hydrocarbons from the older rock,
          MYL and MYH     = maturity of light-end and heavy-end hydrocarbons from the younger rock,

  Each oil charge is simplified here to contain only two groups of
  components: light hydrocarbons (C5-C10) and heavy (C11+) hydrocarbons.
  Thermal maturity - as determined by the aromatic parameters TMBI for the
  light ends (Alexander et al., 1996), and MPI for the heavy ends (Alexander
  et al., 1988) - is taken as the property of interest in the petroleum
  charges received by the reservoir from both basins. This dual source model
  can be digitally imitated by assigning a maturity value 1 for both light
  and heavy components (MYL = 1 and MYH = 1) of the less mature (Eromanga)
  oil, and a maturity value 100 (MOL = 100 and MOH = 100) for the more
  mature  (Cooper) oil (Fig. 1). Upon mixing of two oils each comprising equal
  amounts of light and heavy hydrocarbons (i.e. PYL : PYH = 1 and POL : POH
  =  1), the resulting blend will plot along the straight line EAC (1111), with
  Cooper-to-Eromanga mixing ratios ranging from 0 (at point E) to 100 (at
  point C). However, the larger the compositional contrast between the two
  oils mixing in the reservoir, the greater the deviation from the central
  line EAC.

  Composite oils plotting above this line are the result of mixing of
  gasoline-rich Cooper crude with heavy-end-dominant Eromanga oil. Thus, for
  example, the curve EBC (1221) represents oil pools composed of an Eromanga
  charge in which light ends are half as abundant as heavy-end hydrocarbons
  (PYL : PYH = 1:2) mixed with a Cooper charge containing two times more
  light than heavy hydrocarbons (POL : POH = 2:1). Likewise, data plotting
  along the curve EDC (1551) represent an even greater differential between
  light and heavy hydrocarbons in the Eromanga (1 PYL : PYH  = 1:5) and
  Cooper (POL : POH = 5:1) charges. A hypothetical mixture falling into the
  area below the line EAC in the ML-MH cross plot is geologically improbable,
  as oils of high maturity normally contain more gasoline-range components,
  whereas less mature crudes have more heavy-end hydrocarbons. Therefore, the
  curve EFC (5335) is highly unlikely to occur in nature. Certainly, none of
  the 72 oil and condensate samples from the Cooper and Eromanga Basins
  analysed in this study exhibits any such affinity.

  The demonstrated consistency between the results calculated using this
  model and the actual data set (Figs 1 and 2) suggests that such a
  calculation can be used to more precisely predict the relative
  contributions of multiple sources to an oil accumulation. Various examples
  will be discussed.

  Alexander, R., Larcher, A.V., Kagi R.I. and Price, P.I., 1988. The use of
  plant-derived biomarkers for correlation of oils with source rocks in the
  Cooper/Eromanga Basin system. APEA Journal 28(1), 310-324.
  Alexander, R., Bastow, T.P. and Kagi, R.I., 1996. Novel approaches to the
  determination of the origins of petroleum hydrocarbons in the
  Cooper-Eromanga Basin System. Unpublished report to the Department of Mines
  and Energy, South Australia.


  Xinke received his B. Sc. degree in organic chemistry from Lanzhou
  University (China), an M. Sc. degree in organic geochemistry from Chinese
  Academy of Sciences (CAS).  Since 1988, he has held positions with the
  CAS, and is currently studying at the University of Adelaide for a PhD degree
  in organic geochemistry, under the supervision of Dr. David M. McKirdy.

Tuesday, July 4, 1-00pm

Mr. Mark Tingay - Ph.D. Candidate, NCPGG

In-situ Stress and Overpressures of Brunei Darussalam


  An investigation has been undertaken of the in-situ stress and fluid
  pressures of the Baram Basin in Brunei. The Baram Basin is a Tertiary delta
  with several major petroleum fields. The basin is subject to extreme
  overpressures that, in some cases, reach the lithostatic gradient. The
  implication of in-situ stress and overpressure for sub-surface fluid flow,
  specifically improving hydrocarbon recovery and examining the sealing
  potential of faults, are discussed.

  Leak-off tests and borehole breakouts have been used to determine the
  minimum horizontal stress magnitude and direction. Density logs are used to
  calculate the vertical stress magnitude. Results suggest a weak
  margin-normal maximum horizontal stress orientation.

  Repeat formation tests and mudweights were used to determine pore pressure
  profiles and identify zones of abnormal fluid pressures. Log data and
  modeling are used to examine whether overpressuring is caused by
  disequilibrium compaction or fluid expansion mechanisms.

  Biography of the Speaker
  Mark Tingay was born in Adelaide. He completed his undergraduate and honours
  degrees in geophysics at the Department of Geology and Geophysics at
  Adelaide Uni. Mark Tingay is currently a PhD candidate at the NCPGG.  His
  PhD work is investigating in-situ stresses, neotectonics and overpressures
  of Brunei Darussalam in South-East Asia. He has recently returned from three
  months study with the Geosciences Project into Overpressure (GeoPOP)
  research group at the University of Durham, England.

Thursday, July 27, 1-00pm

Mr. Takeshi Nakanishi - PhD. Candidate, NCPGG

Quantitative geologic risk evaluation and expected net present value evaluation


  Oil and gas exploration is an investment and the aim is to get a profitable
  return. However, there are many aspects that introduce uncertainty and
  therefore increase the risk of losing money. In order to control the
  return, oil companies started quantitative geologic risk evaluation and
  ENPV ( expected net present value) evaluation in their investment projects.
  The companies evaluates a prospect in "geologic chance of success
  (probability of finding oil or gas)" and "probabilistic reserve
  distribution (if oil or gas is found, what volume is recoverable)". The
  reserve distribution is changed to monetary distribution by estimating
  development and production scenarios. The situation is categorized into
  three categories, economic success (get profit), geologic success but
  economic failure (lost money), and geologic failure (lost money). ENPV is
  one of the expected value, the summation of the products of chance and
  monetary value of each situation. ENPV is a tool to find the appropriate
  "entrance fee" to a project, to characterize and compare projects regarding
  risk-return and to make a portfolio.
  It is important to improve evaluation accuracy to better control returns.
  Therefore they also do a reality check of each evaluation and post audit

  Biography of the Speaker
  Takeshi Nakanishi

  The Osaka City Univ., Japan
  MSc in Geology, March 1992
  Thesis: "Middle Miocene Submarine Channel System: the Aishiro Formation in
  the Western Shimane Peninsula, Southwest Japan" (presented in IGC, 1992)

  The Osaka City Univ., Japan
  BSc in Geology, March 1990
  Thesis: "Stratigraphy and Sedimentology of the Middle Miocene Togane
  Formation, Hamada District, Shimane Prefecture" (published)

  April 1998 - January 2000
  Geologist: JNOC Technical Dept., Project Evaluation Dept.
  Basin analysis of the Campos Basin, Brazil.
  Exploration risk analysis of the Browse Basin of the NW-shelf, Australia.
  Establishing the procedure of the quantitative geologic risk analysis and
  economic evaluation in JNOC.

  April 1996 - March 1998
  Well site Geologist: JAPEX (Japan Petroleum Exploration Company), Sapporo
  Oil and gas discovered wells' operation in the northern part of Japan.
  Sedimentology and Sequence Stratigraphy of the coal formation in the
  northern part of Japan.

  April 1992 March 1996
  Geologist: JNOC Technical Dept.
  The East China Sea basin analysis project.
  The North Sea compile project.
  The East Siberia basin analysis project.
  Seismic Acquisition project in Ross Sea, Antarctica.

Tuesday, August 1, 1-00pm

Dr. Xiaowen Sun - Sun Petroleum Geoservices

Natural Fracture Plays of the Southern Cooper and Eastern Warburton
Basins, South Australia


  Detailed studies of natural fractures in the Cooper Basin and the
  underlying Warburton Basin confirm that natural fracture plays are
  important for exploration and production. Natural fractures from the two
  basins are classified and characterised, resulting in delineation of
  orientations of open and partially open fractures, and fracture system
  distribution patterns.

  Natural fractures are identified from selected lithological units in some
  44 wells of the southern Cooper Basin (Sun, in preparation). Generally
  speaking, open fractures are developed mainly within brittle sandstone of
  the Tirrawarra Sandstone. These open fractures are mostly high angle to
  subvertical, with measured apertures of up to 2 mm. Many fractures are
  partly or completely mineralised. Two sets of steeply dipping regional
  fracture systems are essentially similar to those identified from the
  underlying Warburton Basin by Sun (1999, 2000). These regional fractures
  have the most potential for oil and gas production. The deviation angle of
  future wells should be approximately 20( from horizontal in the fracture
  zones to maximise the likelihood of such wells encountering high angle open
  fractures. A semi-quantitative estimate of fracture density has been
  determined for 41 wells. The greatest fracture density is located in major
  fault (e.g. strike-slip) zones and structural culminations (e.g. the GMI

  Considerable information has been gathered from a detailed core study of 91
  wells in conjunction with the use of dipmeters and FMS logs from 27 wells
  in the Warburton Basin (Sun, 1999, 2000). From these data, two systems of
  orthogonal high-angle fracture sets (four fractures) have been identified
  for the first time. They extend across local structures beneath the Cooper
  Basin in South Australia. System I has a pair of orthogonal fractures,
  striking NNE-SSW (20-200°) and ESE-WNW (110-290°). System II has a pair of
  orthogonal fracture sets, striking NE-SW (60-240°) and NW-SE (150-330°).
  Open, steeply dipping SW fractures striking WNW and NW within Systems I and
  II are interpreted from FMS both in Lycosa 1 and Malgoona 4, and also in
  core 1 of Lycosa 1. The results indicate that an optimum well trajectory
  designed to maximise intersection with open natural fractures should be
  200-210° and 240-250°, and possibly also 270-290°. The deviation angle
  should be approximately 30° from horizontal in the fracture zone due to the
  high-angle and subvertical fracture dips. A semi-quantitative estimate of
  fracture density has been determined for 91 wells, and the greatest
  fracture density is located in major fault zones or structural
  culminations. Generally speaking, fractures are mainly developed within
  brittle rather than ductile rock types if they are frequently interbedded.
  Fracture fairways exist in brittle sandstone, dolomite and ignimbrite, and
  any rock types with the above suggested orientations of the two systems of
  orthogonal fracture sets. The basement fracture play suggests that future
  wells should be drilled at least 120 m (vertical depth) into the Warburton
  Basin where Cooper Basin source rocks lie down dip in association with
  either structural or stratigraphic traps. Proper testing for hydrocarbons
  in the Warburton Basin is recommended.

  Sun, X., 1999. Fracture analysis of the eastern Warburton Basin (Early
  Palaeozoic), South Australia. South Australia. Department of Primary
  Industries and Resources. Report Book 99/14. 52 pp, 38 figs, 12 tabs.
  Sun, X., 2000. Natural fracture plays of the southern Cooper and eastern
  Warburton Basins, South Australia. In: Wood, G.R. (Compiler). Second Sprigg
  Symposium, Frontier Basins, frontier ideas. June 29-30th, 2000. Extended
  abstract. Geological Society of Australia Abstract, No.60:88-91.
  Sun, X., in preparation. Natural fractures of the southern Cooper Basin,
  South Australia. South Australia. Department of Primary Industries and
  Resources. Report Book.

  Biography of the Speaker
  Xiaowen Sun graduated with a BSc (Hons) from the Nanjing University, and
  then obtained a MSc from Nanjing Institute of Geology and Palaeontology,
  Academia Sinica, China, and a Ph.D. in Geology and Geophysics from the
  National Centre for Petroleum Geology & Geophysics in 1997. Xiaowen has
  since been undertaking a joint project sponsored by the Petroleum Group of
  the South Australian Department of Primary Industries and Resources (PIRSA)
  for 3 years, working on a fracture and reservoir study of the Warburton and
  Cooper Basins, and revision of boundaries between the Warburton and
  overlying Cooper and Eromanga Basins. She has extensive training and
  experience in petroleum exploration, specialising in Early Palaeozoic basin
  studies, sequence stratigraphy and sedimentology, and naturally fractured
  reservoirs of the Warburton, Cooper and Eromanga Basins. In November, 1999,
  she established a geological consultancy - Sun Petroleum Geoservices that
  offers various geological services to petroleum industry and government
  Currently she undertakes a study of electrofacies of the Cooper Basin for
  the Petroleum Group of PIRSA. Xiaowen has close ties with the petroleum
  industry and research organisations in China.

Tuesday, August 8, 1-00pm

Dr. Simon C. Lang - Associate Professor, Clastic Sedimentology and Sequence Stratigraphy, NCPGG

Applications of Modern and Ancient Geological Analogues in
Characterisation of Fluvial and Fluvial-Lacustrine Deltaic Reservoirs in the Cooper Basin

  This presentation was given at the APPEA 2000 conference in Brisbane, and
  is repeated here in a slightly expanded form.  The paper was "runner-up"
  for both best technical paper and best technical presentation at the
  conference, and is based on the APPEA 2000 paper by S.C. Lang, J. Kassan,
  J.M. Benson, C.A.Grasso and L.C. Avenell (The APPEA Journal, Vol 40, 1,

  Reservoir characterisation in fluvial and fluvial-lacustrine delta
  successions is enhanced by the use of appropriate modern and ancient
  analogues to understand subsurface reservoir architecture and to help build
  appropriately scaled reservoir models.  Two case studies of reservoir
  characterisation in the Cooper Basin are used to illustrate the value of
  analogues. Firstly the Late Permian Toolachee Formation crevasse splay
  reservoirs of the Cooper Basin, SW Queensland are outlined, and analogues
  from the Ob' River in Western Siberia illustrate the relative scale of
  crevasse splay deposits within avulsion belts in a cool-temperate
  peat-forming environment. The South Blackwater coal mine in the Permian
  Bowen Basin is used as an analogue to quantify the 3-D geometry, and
  reservoir architecture of crevasse splays and to highlight subsurface
  reservoir heterogeneity.
  Secondly, the Early Permian Epsilon Formation shallow water lacustrine
  delta reservoirs are outlined, and analogues from the extant geometry of
  the distributary channels and relict mouth bar deposits from the fluvial
  dominated Neales Delta in Lake Eyre are used to interpret flow rate decline
  trends and probable reservoir architecture. The subsurface Tertiary
  lacustrine deltaic complex of the Sirikit Field from the Phitsanulok Basin,
  central Thailand, is selected as an ancient analogue for the multistorey
  reservoirs developed within amalgamated mouth bar complexes intersected in
  the lower Epsilon Formation.

  Speaker Biography
  Simon Lang graduated from the University of Queensland in 1985 with a BSc
  (Hons) in Geology and Mineralogy, and later obtained his PhD (part-time)
  also from University of Queensland in 1994.  From 1979 to 1992 he worked as
  a geological technician and geologist for the Geological Survey of
  Queensland in the Palaeontology, and Regional Mapping Sections mainly in
  central and northern Queensland.  Simon joined Queensland University of
  Technology in 1992 as a lecturer in sedimentology and stratigraphy during
  which time he supervised petroleum and mineral related postgraduate
  projects in a range of basins in Australia, Indonesia, PNG, and Venezuela.
  In addition he developed a reservoir analogues research program based on
  sedimentology and seismic/sequence stratigraphy of Moreton Bay and the SE
  Queensland continental shelf, as well as working on other modern
  depositional environments in (eg. Mahakam Delta, Neales Delta in Lake Eyre,
  Theodolite Creek in Hervey Bay, Batemans Bay etc.).

  Simon joined the National Centre for Petroleum Geology and Geophysics as
  Associate Professor in sedimentology and sequence stratigraphy in 1999, and
  is currently working on reservoir characterisation for the APCRC program on
  Geological disposal of CO2 (GEODISC). He is involved in several reservoir
  characterisation projects in the Cooper-Eromanga Basins, and is supervising
  numerous students working on basins throughout Australia.  Simon is a
  member of PESA, GSA, AAPG, SEPM, IAS and IPA.

Tuesday, August 15, 1-00pm

Prof. Richard Hillis - State of South Australia Chair in Petroleum Reservoir
Properties/Petrophysics, NCPGG

Basin-Centred Gas Accumulations:
A New Exploration Paradigm and its Application in Australia

  This presentation has been previously presented at the recent Sprigg
  Symposium and Resources Week conferences in Adelaide, and is repeated here
  in a slightly expanded form.

  Basin-centred gas accumulations present a different paradigm from standard
  trapping mechanisms associated with the conventional hydrocarbon system.
  Basin-centred gas may lie downdip from water with no conventional
  impermeable barrier between. Accumulations are not necessarily constrained
  either by structural or stratigraphic closure. In the Elmworth Field of
  western Canada, the entire Mesozoic section from approximately 1 to 3 km
  depth contains gas in every stringer of reservoir rock. Basin-centred gas
  accumulations may be indicated by a regional increase in resistivity in
  electric log data from the basin flanks to the basin-centre. Subsequent
  testing may reveal continuous gas saturation and the absence of a water
  leg. Basin-centred gas reservoirs of the type first recognised in western
  Canada may occur in the trough areas of the Cooper Basin, South Australia.

  This presentation describes the North American experience with regard to
  basin-centred gas, presents the evidence for a basin-centred gas type
  accumulation in the Cooper Basin and describes a new exploration paradigm
  that must be applied to its discovery and exploitation.

  If basin-centred gas accumulations are recognised, exploration need not be
  solely concerned with conventional traps, because below a critical pressure
  seal the entire basin is gas saturated. The nature of the sealing
  characteristics of this boundary are debated but may relate to low
  permeability, 'tight' units being permeable to single-phase flow and
  impermeable to multi-phase flow during hydrocarbon generation and primary
  migration. In the basins of the western United States 80% of cumulative gas
  production in these basins comes from within 600 m beneath the pressure seal.

  If electric log and testing data support the possible occurrence of
  basin-centred gas, it is necessary to delineate the regional pressure seal
  beneath which the basin is gas saturated (sonic velocity data being the
  most widely used tool) . Having recognised, and in so far as possible
  mapped the extent of the regional pressure seal, the key to the successful
  exploitation of basin-centred gas lies in the recognition of natural
  sweetspots (structural, sedimentological and/or diagenetic) beneath the
  regional pressure seal. For example, shoreline/barrier bar sands have been
  particularly important in providing commercial flows of basin-centred gas
  in western North America. Such sweetspots may not be 'tight' per se, but
  their identification, outside of structural closure in basin-centred gas
  accumulations, requires the understanding and application of a new
  exploration paradigm.

  Non-conventional engineering approaches such as horizontal drilling and
  fracture stimulation are critical to the exploitation of both conventional
  and basin-centred tight gas resources. Furthermore, low permeability tight
  gas reservoirs are particularly prone to formation damage, requiring
  drilling and completion strategies designed to minimise this. However,
  engineering approaches are best applied to the optimum geological
  environment  (ie. sweetspots), and may not be able to deliver commercial
  production in unfavourable geological environments.

  Richard Hillis holds the State of South Australia Chair in Petroleum
  Reservoir Properties/Petrophysics at the National Centre for Petroleum
  Geology and Geophysics (NCPGG), University of Adelaide. He graduated BSc
  (Hons) from Imperial College (London, 1985), and PhD from the University of
  Edinburgh (1989). After seven years at the University of Adelaide's
  Department of Geology and Geophysics, Richard joined the NCPGG in 1999. His
  main research interests are in sedimentary basin tectonics and petroleum
  geomechanics. He has approximately 50 published papers and has consulted to
  12 Australian and international oil companies. He is currently SA Branch
  president of the ASEG. Richard is a member of AAPG, AGU, ASEG, EAGE, GSA,
  GSL, PESA and SEG.

Tuesday, September 5, 1-00pm

Dr. Jim Jago - Associate Professor, School of Geoscience, Minerals and Civil Engineering,
University of South Australia

Cambrian Geology and Palaeontology, Northern Victoria Land, Antarctica

  Almost all the fossiliferous Cambrian rocks of Northern Victoria Land
  outcrop within the fault-bounded strip of sediments and volcanics known as
  the Bowers Terrane. The Bowers Terrane is orientated NW-SE; it is about
  400km long and up to 40km wide. It is bordered to the southwest by a
  Precambrian metamorphic/igneous complex (Wilson Group in the Lanterman
  Terrane) and to the northeast by a metasedimentary flysch unit (Robertson
  Bay Group making up the Robertson Bay Terrane). Considerable horizontal
  displacement of the three crustal blocks has been inferred although views
  differ as to the direction and amount of relative movement on the
  intervening faults.

  In the Bowers Terrane the Molar Formation is the lowest unit. It comprises
  a succession of turbidites and basic volcanics. The age range of the Molar
  Formation is from Boomerangian (or older) to Mindyallan. There is a
  diachronous contact with the overlying Spurs Formation. Regionally, the
  stratigraphic transition from Molar to Spurs Formation is gradational and
  is marked by the disappearance of turbiditic sandstone, which is abundant
  in the Molar, and volcaniclastic detritus, which is locally abundant.
  Limestone-bearing debris flow conglomerates, rare in the Molar Formation,
  are common in the Spurs Formation. The Spurs Formation (Boomerangian to
  Idamean) comprises a shallowing upwards succession of siltstones,
  sandstones and limestones with a corresponding change in fossil content.
  The Spurs Formation is overlain with unconformity by the Leap Year Group
  that is mainly of fluvial origin, although some marine influence is marked
  by the presence of trace fossils. At an isolated locality within the
  Robertson Bay Group a very Late Cambrian trilobite-conodont assemblage is
  known from limestone olistoliths within a shale-sandstone-conglomerate

  Trilobites are abundant at various localities. Faunal affinities are mainly
  with the Ellsworth Mountains (West Antarctica), New Zealand, Tasmania,
  Queensland and China. Other fossils include hyolithids plus articulate and
  inarticulate brachiopods.

  Educational Qualifications: B.Sc. (hons) (Tasmania, 1966), Ph. D.
  (Adelaide, 1973)
  Employment: Lecturer, Senior Lecturer, and Associate Professor in Applied
  Geology within the University of South Australia (formerly South Australian
  Institute of Technology) since 1971.
  Major Research Activities: Cambrian geology and biostratigraphy of
  Tasmania, South Australia and Antarctica. Stratigraphy, sedimentology and
  mineralization of the Kanmantoo and Lake Frome Groups, South Australia.
  This has been supported by ASAC and/or ARGS/ ARC Large and Small grants to
  study the Cambrian faunas and geology of Tasmania, South Australia and
  Antarctica. These have been held continuously since 1973.. In 1999 and 2000
  an ARC Small Grant has been held to study the Cambrian tectono-sedimentary
  history of the Adelaide Fold Belt.
  ARC Collaborative Grant: In 1995-97 JBJ held an ARC Collaborative Grant to
  study the relationship between the mineralization and sequence stratigraphy
  of the Kanmantoo Group, South Australia.


Tuesday, September 15, 1-00pm

Dr. Scott D. Mildren - Postdoctoral Fellow, NCPGG, University of Adelaide.

Stresses and Structural Permeability: Applications to Petroleum Exploration

  Structural permeability is described by Sibson (1996) as the "infiltration
  of pressurised fluids into stressed heterogenous crust, perhaps along
  existing discontinuities which may induce a range of differently oriented
  brittle structures that become progressively interlinked into a structural
  mesh which adds to the permeability of the rock mass".  Given that
  permeability enhancement through faulting and fracturing is dictated by the
  balance between the contemporary differential stress and rock strength,
  these data can be used to predict the occurrence of permeability meshes.

  A structural permeability stereonet can be constructed for a given stress
  regime illustrating the likelihood of fracture formation/reactivation for
  all possible orientations. A relative or absolute scale can be implemented
  depending on the availability of failure envelope data.  This methodology
  has been applied to two petroleum-related scenarios: risking dynamic
  fault-seal breach and predicting fracture susceptibility for fracture

  Biography of the Speaker
  Scott completed his PhD on 'The Contemporary Stress Field of the Northern
  Australian Margin and Collision-Related Tectonism' at the University of
  Adelaide in 1997 and took up a position as structural geologist with Z&S
  (Asia) Ltd. (now Baker Atlas Geoscience).  At Z&S he interpreted
  resistivity and acoustic image data with application to insitu stresses and
  fracture characterisation.

  Scott is currently researching in conjunction with Santos, tight gas
  reservoirs in the Nappamerri Trough, Cooper Basin as part of an ARC SPIRT
  grant.  Other interests include various petroleum applications of in situ
  stress, rock strength determination and interpretation of stress induced
  features from image logs.  He is a member of SPE, PESA and AAPG.

Tuesday, September 19, 1-00pm

Dr. David M. McKirdy - Associate Professor
Organic Geochemistry in Basin Analysis Group, Department of Geology and
Geophysics, University of Adelaide

A pilot FTSE study of secondary migration and reservoir filling in the
Cooper/Eromanga Basin, South Australia

  The processes of secondary oil migration and reservoir filling are two of
  the least understood aspects of any petroleum system. This study makes use
  of the flow-through solvent extraction (FTSE) cell, a novel high-pressure
  device that allows elucidation of the charge history of an oil-bearing
  reservoir rock. The FTSE technique involves the stepwise sequential
  extraction of residual petroleum fluids from sandstone core plugs. In this
  way the pore-filling processes which have occurred in nature can be
  reversed with respect to their timing. Those parts of a heterogeneous pore
  network that were the last to be filled by petroleum in the subsurface can
  in this experimental procedure be emptied first (FTSE steps 1-3). Thus,
  individual petroleum charges which may have filled a trap over an extended
  period of geologic time can be retrieved separately from oil-saturated
  reservoir rocks and/or carrier beds. The source and maturity signatures of
  these core-plug extracts, as determined by gas chromatography (GC), gas
  chromatography-mass spectrometry (GC-MS) and compound-specific isotopic
  analysis (CSIA) may then be used to reconstruct the field's filling history.

  The present study encompasses oils and core samples of source and reservoir
  facies from four fields on the southwestern flank of the Nappamerri Trough.
  These fields (Thurakinna, Garanjanie, Dirkala and Wancoocha) comprise oil
  and gas accumulations in stacked Permian, Jurassic and Cretaceous
  reservoirs that lie along a notional fill-and-spill pathway charged by
  updip migration from a Permian hydrocarbon kitchen. Residual oils recovered
  by FTSE and conventional bulk extraction of sandstones from the Permian
  Patchawarra Formation and Murteree Shale, the Jurassic Hutton Sandstone and
  Birkhead Formation, and the Cretaceous Murta Formation have been compared
  with crude oils obtained by drill stem testing of the same units. The
  points of comparison, and their molecular basis, were bulk composition
  (percent saturates, aromatics & NSO compounds); thermal maturity
  (MPI-derived vitrinite reflectance, Rc); and source affinity (araucariacean
  conifer biomarker ratios).

  This first application of FTSE technology to a major Australian petroleum
  province has confirmed significant lateral and vertical secondary migration
  of Permian oil in the southwestern Cooper and Eromanga Basins; and revealed
  a complex charge history for its Jurassic and Cretaceous reservoirs.
  Residual and DST oils recovered from sands in the Permian Patchawarra
  Formation and Murteree Shale are all of intra-Permian origin.  Maximum
  lateral secondary migration distances of oil within the Patchawarra
  Formation are in the range 4-8 km. Oil in the Jurassic reservoirs (Hutton,
  Birkhead) at Dirkala and Wancoocha displays a gross stratigraphic
  segregation according to maturity. The least mature oil (Rc = 0.7%) is
  located at the top of the oil column.  These early oils, and the more
  mature residual oils lower in each structure (Rc = 0.7-0.8%), are all of
  Jurassic origin. Anomalously mature residual oils (Rc = 1.0-1.1%) at the
  base of the oil column in these two fields are of mixed Permian-Jurassic
  source affinity. They imply leakage of Permian hydrocarbons past the zero
  edge of the Nappamerri seal; and compartmentalisation of the Jurassic
  reservoirs. DST oils from Cretaceous reservoirs (Cadna-owie, Murta) in the
  study area have uniformly low maturities (Rc = 0.63-0.69%). Those at
  Wancoocha and Dirkala are of Jurassic (Birkhead) origin. However, the
  biomarker signature of Murta oil in the more basinward Garanjanie field
  indicates an additional contribution from a low-maturity Permian source.

  Biography of the Speaker
  David McKirdy is a graduate of the University of Adelaide (B.Sc. Hons,
  M.Sc.) and the Australian National University (Ph.D.). Since 1970 he has
  held positions with the Bureau of Mineral Resources (now AGSO), the South
  Australian Department of Mines and Energy (now PIRSA), Conoco Inc. and
  AMDEL Ltd. In 1987 David returned to the Department of Geology and
  Geophysics at University of Adelaide where he is currently deputy head and
  an associate professor undertaking research in source rock and petroleum
  geochemistry, isotope chemostratigraphy, and the use of organic
  geochemistry as a tool in basin analysis. He is the author or co-author of
  64 scientific papers, 74 published abstracts, 27 open-file reports and 151
  company and consultancy reports; and co-editor of two conference
  proceedings volumes (one published as a book by Springer-Verlag) and a
  field excursion guide. In 1996 David was awarded the Australian Organic
  Geochemistry Medal. He is a member of the GS, GSA, SEPM, EAOG, PESA, AAAPG
  and RSSA.


Tuesday, September 26, 1-00pm

Mr. Paul V. Grech -  Data Management Officer, Seals Project, NCPGG

Continental Sequence Stratigraphic Concepts - A Review

  In marine influenced depositional environments, the lateral facies changes
  in response to variations in relative sea level are reasonably well
  understood.  The sedimentary history of basins in a sequence stratigraphic
  context has been well documented in numerous publications.  The driving
  force behind the different facies and their relationship, both laterally
  and vertically, is the fluctuation in the base level, which in a marine
  situation, is the relative sea level.  When discussing terrestrial
  environments however, the effects of relative sea level changes decrease
  upstream, whereas base level changes are more prominently driven by
  tectonic effects and sediment supply.  The facies variations become less
  pronounced and have been described as 'internally complex rock piles, where
  consistent correlation is difficult because of abrupt and often random
  facies changes' (Legarreta et al., 1993).  Recently however, fluvial
  channel stacking patterns have been recognised to follow a pattern dictated
  by the resultant base level variations, and hence providing a new tool with
  which to predict lateral and vertical facies variations in a continental

  The basis for this sequence stratigraphic interpretation of continental
  environments are the fluvial channel stacking patterns.  Within the
  lowstand systems tract (LST) and the late highstand systems tract (HST),
  channel sands are amalgamated laterally and vertically, while similar sands
  in the transgressive systems tract (TST) and in the early HST are isolated.
   Sequence formation is controlled by third-order base level cycles, while
  fourth and fifth-order fluctuations control deposition within the systems

  Accommodation during LST deposition is minimal, before base level
  eventually starts rising at a slow rate.  The TS is the surface at which
  point the rate of rise of base level starts to increase rapidly.  This
  acceleration continues until a point is reached where the rate of rise
  starts to decrease, the surface of maximum rate of base level rise or the
  surface of maximum transgression (SMT).  During HST deposition, the rate of
  accommodation creation decreases until it is again stationary and
  eventually becomes negative.  When this point is reached, erosion starts to
  take place, forming the sequence boundary (SB) of the following sequence.

  The proposed model is mainly based on a review of work carried out by
  Legarreta et al. (1993), Shanley and Mc Cabe (1994), Aitken and Flint
  (1995), Olsen et al. (1995), and Allen et al. (1996).

  Biography of the Speaker
  Paul graduated with a BSc (Hons) from the University of Technology, Sydney.
   In 1994 he commenced his PhD studies at the NCPGG on the sedimentology and
  stratigraphy of the Rewan Group, Bowen Basin.  During his last three years
  of his PhD he worked at Wiltshire Geological Services (WGS) interpreting
  and correlating wireline logs in a major study of the North West Shelf.  He
  has interpreted all open file wireline logs from the Bonaparte, Vulcan,
  Browse, Canning and Carnarvon Basins.  Recently he joined the NCPGG Seals
  Project as a researcher and a data management officer.

Tuesday, October 3, 1-00pm

Dr. John Warren - Professor of Petroleum Geoscience, Department of Petroleum Geoscience,
University Brunei Darussalam

Recognising and characterising tidally-influenced and shoreface sequences
in the Miocene reservoirs of Brunei by integrating wireline/image data with
outcrop and core measurement

  Sandstone reservoirs in offshore Brunei include interbedded
  tidally-influenced and shoreface sediments. Both are very good quality
  sands but have not been previously separated in the subsurface using
  conventional wireline logs. Through the integration of outcrop, core,
  conventional and image (OBDT and FMI) logs, as outlined in this talk,
  tidally-influenced and shoreface environments are now can be successfully

  Tidally-influenced sand units, with lateral extents of up to 3 km and
  thicknesses up to 19m show dip patterns with typically decreasing amplitude
  trends toward differentially stacked channel axes. In contrast, dip
  patterns in the shoreface sands show scattered dip values and dip
  directions indicating deposition as sub-horizontal parallel, to low angle
  cross-bedded structures, with occasional swaly and hummocky cross
  stratification. Shoreface sand intervals also entrained some blank zones in
  the dip track indicating high degrees of bioturbation.

  Plug and trim end analyses were integrated with the FMI and core
  lithofacies interpretation to better understand variation of the reservoir
  quality in the two types of sand. Tidal sands are better potential
  reservoirs compared with shoreface sands. For example in one offshore
  field, average porosity and permeability in laminated tidal sands is
  21.78%, 745.61mD and 20.90%, 489mD for bioturbated tidal sands. Both
  averages are higher than for equivalent shoreface sands in the same wells,
  which have average porosity and permeability of 19.46%, 231.99mD for
  laminated sands and 15.83%, 211.3mD for bioturbated sands. Compaction
  (especially in muddier sands) and cementation have lowered reservoir
  porosity and permeability in both settings, by compressing, filling and
  even completely blocking pore spaces with detrital and authigenic clays.
  Dissolution processes have locally enhanced reservoir porosity and
  permeability by opening new pore throats and connecting isolated pores.
  Diagenesis has influenced reservoir sand quality but the fundamental
  control is depositional setting.

  Biography of the Speaker
  Dr Warren is a currently a contract Professor in the Department of
  Petroleum Geoscience at the University of Brunei Darussalam (UBD). He is
  also an Executive Director of JK Resources Pty. Ltd. From 1993 to 1995 he
  was Director of the Key Centre for Resource Exploration and Professor of
  Petroleum Geology in the School of Applied Geology at Curtin University in
  Perth, Western Australia. In 1989-1992 he was Principal Research Scientist
  at the National Centre of Petroleum Geology and Geophysics in Adelaide and
  before that spent 8 years on the faculty at the University of Texas in
  Austin.  In the early and mid seventies he worked for the Geological Survey
  of South Australia and Esso Minerals Australia.
  Dr Warren specialises in rock matrix characterisation in both the petroleum
  and minerals industries. He has conducted and supervised applied and pure
  research in modern and ancient sediments of Australia, Canada, Mexico, the
  Middle East, the North Sea, South-east Asia and the United States. He has
  worked as a consultant dealing with matrix-related problems in exploration
  programs conducted by Asia-Pacific Potash, BHP Minerals, BHP Petroleum,
  Homestake, Pasminco, Shell, Chevron, Texaco, Statoil, Woodside Petroleum
  and others. He has also served as a technical expert in evaporites for the
  AAPG, BBC, IHRDC, and New World Horizons. In 1999 he published his second
  book dealing with Evaporites.  In 1986 he was appointed for six months by
  the Nordic Council of Ministers as the visiting professor in Nordic
  Petroleum Geology based at the University of Copenhagen. In 1990 Dr Warren
  was appointed to the World Bank Panel of Experts. In addition to two books
  and a number of book chapters, he has published more than 50 scientific
  articles in major refereed journals including: American Association of
  Petroleum Geologists Bulletin, APEA Journal, Australian Journal of Earth
  Sciences, Earth Science Reviews, Journal of Sedimentary Petrology,
  Geochimica Cosmochimica Acta, Geotimes, PESA Journal, Sedimentary Geology
  and Sedimentology.

Thursday, October 5, 2000, 1-00pm

Dr. Alton Brown

  1. Matrix Seals to Petroleum Accumulations: Empirical Evidence and Wireline
  Characterization (1:00 PM)
  2. Fault Sealing Problems:  Influence on Petroleum Migration, Criteria for
  Documentation, and Implications for Field Development (2:00 PM)

Bookings not required - Gratis for PIRSA staff, students/staff of the U of Adelaide / NCPGG & PESA / ASEG Mbrs

1- Matrix Seals to Petroleum Accumulations: Empirical Evidence and Wireline

  Matrix sealing is probably more important than fault sealing, because if no
  matrix seal is present, no petroleum will accumulate even if trapping
  faults seal.  Two approaches are presented for evaluating real (as compared
  to laboratory) matrix sealing.  First, controls on actual trapped column
  height will be evaluated to see how much of a gas column seals do hold.
  Second, strategies for characterizing matrix seals from wireline log
  response will be investigated.
  Sixty of the highest gas columns were evaluated for geological controls on
  gas column height.  Most of these traps, including the tallest, are filled
  to spill.  Most have fault juxtaposition seal within the gas column.  Few
  of these traps have documented leakage, but most of these traps are young,
  so slow subtle leakage may destroy tall accumulations through time.
  Mudrocks and evaporites comprise most seals.   Seal capacity is independent
  of mudrock depositional environment.  Argillaceous siltstones act as seals
  to tall columns only at great depth, where porosity reduction is great and
  ductility of the siltstone may be sufficient to prevent fracture leakage.
  Capillary displacement pressure of mudrocks cannot be directly measured
  with any log, even standard NMR logs.  Wireline evaluation of seal capacity
  must be done indirectly, by measuring some property which correlates to
  capillary displacement pressure.  The two rock variables which best
  correlate with capillary displacement pressure are the permeability and the
  rock surface area.  The wireline log most likely to indicate seal capacity
  is the resistivity log, if other logs can estimate porosity and
  temperature.  The interaction of water with clay minerals creates a
  two-water system, so theoretically, the cation exchange capacity (CEC) can
  be calculated from resistivity if temperature, water salinity, and porosity
  are known.  Water salinity is estimated from Pickett plots of nearby clean
  sandstones.  Capillary displacement pressure correlates to surface area,
  and surface area correlates to CEC. This methodology has not been field
  tested, so confidence interval for predicted seal capacity cannot yet be

  2- Fault Sealing Problems: Influence on Petroleum Migration, Criteria for
  Documentation, and Implications for Field Development

  Fault seals and fault migration pathways are commonly interpreted as a
  function of fault geometry, fault juxtaposition and fault fill
  characteristics only. The presence and dip of beds intersecting
  transmissive faults are also important; in many cases, these
  characteristics render discussion of fault transmissivity moot. Along-fault
  transmissivity can only be significant if the fault connects to higher
  transmissive bed, so that a migration circuit can be completed.  The
  bedding dip at intersection with the fault determines if a fault is charged
  and where along the fault petroleum may migrate. Where carrier bed dip
  diverges from a location on the fault, petroleum is focused to transmissive
  faults, and vertical migration on the fault is localized.  Although the
  entire fault may be transmissive, only  part of the fault may transfer
  potentially economic quantities of petroleum.  Charge from the fault to
  structures not closed by the fault require carrier bed dip towards the fault.
  The second issue deals with the nature of capillary seal failure.
  Capillary seals fail where the capillary pressure exceeds some threshold,
  not where a cross-fault pressure differential is exceeded, as has been
  commonly published.  Prior to intrusion of petroleum into fault seal pores,
  the ambient fluid is essentially static water connected to the regional
  aquifer.  The intrusion process therefore works against water in the pore,
  and is not aided by a high capillary pressure on the other side of the
  fault.  This same analysis can help explain pressure communication across
  faults in producing fields.  In particular, fault seal breakdown is
  sometimes inferred to be a mechanical property.  However, similar, abrupt,
  initiation of pressure communication can be explained by capillary sealing
  and by three-dimensional effects with pressure transmission through the
  water leg.

  FIT: New approaches for log interpretation pose general interest to many.
  Offset seal and breaching are critical uncertainties in play fairways
  explored on- and offshore Australia

  Biography of the Speaker
  Alton Brown (B.Sc., Baylor University, TX, USA; Ph.D., Brown University,
  RI, USA) worked for ARCO from 1980 - 2000 in exploration research.  He
  supported prospect development and appraisal, regional geological studies,
  and theoretical analysis of problems relevant to exploration. Major
  accomplishments at ARCO include:  development of strategies for reservoir
  quality prediction, algorithms for numerical simulation of carbonate
  porosity evolution, improved models for prediction of non-hydrocarbon
  gases, better estimation of expulsion and secondary migration efficiencies,
  development of an integrated approach to evaluation of petroleum migration,
  and improved methodologies for hydrodynamic mapping in complex terrains.
  He was also a member of teams responsible for several major ARCO gas
  discoveries.  With the merger of ARCO and BPA, he elected early retirement
  after attaining a position of senior exploration advisor, high on ARCO's
  technical ladder. Many of results of ARCO research have been released and
  will be published over the next few years.  He is currently a semi-retired

Tuesday, October 10, 2000, 11-00am

Dr. Richard E. Swarbrick - GeoPOP, University of Durham, Durham UK

The challenge of porosity based pore pressure prediction

  Porosity is used as a rock property implicitly reflecting the degree of
  compaction of sediment. The porosity values may be derived from wireline
  response, or a porosity attribute may be used directly, for example
  velocity data derived from seismic. The methods employed in porosity based
  pore pressure prediction, first developed in areas such as the Gulf of
  Mexico, have been used for several decades. More recently the introduction
  of LWD/MWD tools has advanced the application of porosity-based pore
  pressure prediction to real-time. Furthermore newly emerging plays with
  high reserves replacement potential include the deep-water sediments of
  ocean margins worldwide, sub-salt reserves and high-pressure
  high-temperature environments, all of which are subject to significant
  overpressure. This talk examines the methodology and assumptions involved
  in extracting pore pressure prediction based on porosity, and strives to
  comment on the challenges which exist in particular environments.


Tuesday, October 31, 2000, 1-00pm

Dr. Deborah Bliefnick - Senior reservoir geologist/carbonate sedimentologist
BG Technology/BG International, Loughborough, England

Famennian - Artinskian Sedimentology, Palaeoenvironments and Development
of the Karachaganak Platform, North Caspian Basin, Kazakhstan

 Sedimentological, stratigraphic and palaeoenvironmental studies of a
 representative set of core samples have been carried out as part of an
 integrated geological characterisation of the Karachaganak
 gas-condensate-oil reservoir. Results from this study have been used to
 refine the established model of platform architecture and evolution, to
 define an objective facies scheme, and to establish environmental controls
 on facies distributions. The influence of facies on reservoir heterogeneity
 was then determined, and the appropriate geological analogues for future
 investigation were identified.
 Limited data suggest that the Famennian - Tournaisian of Karachaganak
 consists of a restricted, shallow marine to peritidal ramp succession
 composed of fine grained packstones and wackestones dominated by peloids,
 pellets, palaeoberesellids, red algae, foraminifera (including
 parathuramminids) and calcispheres.
 The Middle Visean to Bashkirian interval in Karachaganak comprises an
 isolated flat-topped platform with steep margins and an atoll-like
 morphology. A broad, aggradational, biohermal outer zone surrounds a
 relatively small inner zone dominated by skeletal grainstones and
 packstones. Skeletal components of the bioherms are dominated by
 palaeoberesellid algae with subordinate sponges and rare bryozoa. Aragonite
 cementstones are very abundant, and are associated with microbialite
 crusts. There is a perplexing lack of shallow-water, high-energy platform
 margin grainstone or framestone facies, and the steep cement-rich margins
 are unusual for well-documented platforms of this age. Shallow inner
 platform deposits contain green algae such as Koninckopora and rare ooids,
 as well as fibrous calcite marine cements and local vadose features.
 Crinoids, brachiopods and red algae dominate the deeper water equivalents.
 These detrital facies and cements are more typical of contemporaneous
 platform interior deposits and the strata would be expected to show
 metre-scale cyclicity in response to glacio-eustatic sea level changes.
 However, this is not apparent in well logs, suggesting that combinations of
 stratigraphic condensation, complex stacking patterns due to lateral facies
 changes, and diagenetic overprinting have obscured any primary pore system
 In the Lower Permian Karachaganak was an isolated aggradational bank with
 bioherm-dominated pinnacles. These were flanked or capped by
 bioherm-derived breccias, grainstones and packstones, and surrounded by
 crinoid ± fusuline-rich packstones and wackestones. A suite of
 depth-related bioherm types developed in response to relative sea-level
 changes. Shallowest, Palaeoaplysina-phylloid bioherms are restricted to the
 Sakmarian. Palaeoaplysina is much less abundant than in many coeval
 platform margins. Relatively shallow bioherms in the Asselian are dominated
 by phylloid algae, sponges, Tubiphytes and local Archaeolithoporella.
 Deeper water bioherms in the Asselian and Artinskian contain abundant
 bryozoa and/or Tubiphytes, locally with solitary corals. All of these
 skeletal bioherms are extensively cemented by fibrous calcite marine
 cements. Additionally, microbialite-rich bioherms with aragonite cements
 are present in both the Asselian and Artinskian. A major development of
 aragonite cementstones in the Artinskian immediately preceded basin
 isolation and evaporite deposition during the Kungurian.

 Biography of the Speaker
 An experienced Senior Reservoir Geologist with experience in international
 teams and joint ventures and expertise in carbonate reservoir
 characterisation, quality prediction, sedimentology and diagenesis, as well
 as training of explorationists and engineers.

 Debbie graduated with BS Honors in geology, including bachelor's thesis in
 sedimentology and stratigraphy from University of Illinois,
 Champaign-Urbana, Illinois in 1975 and a PhD on sedimentology and
 diagenesis of modern carbonate buildups on the Great Bahama Banks from
 University of California, Santa Cruz, CA in 1980

 Her work experience includes: Senior reservoir geologist/carbonate
 sedimentologist with BG Technology/BG International, Loughborough, England
 98 - Present.
 Sedimentologist, project leader, manager 92 - 98 with IKU Petroleum
 Research, Trondheim, Norway
 Senior geologist/reservoir geologist 88 - 92 with ARCO Oil and Gas Co.,
 Research Center, Plano, Texa
 Regional stratigrapher, Southern Region 85 - 88 with Chevron, USA,
 Exploration, Houston, Texas
 Geologist from 80 - 85 with Gulf Oil Co., Technical Service Center,
 Houston, Texas
 Sedimentologist from 80 - 80 involving in the Deep Sea Drilling Project,
 Leg 76, Blake-Bahama Basin, Western North Atlantic Ocean.

Friday, November 17, 2000, 1-00pm

Ms. Catherine Gibson-Poole
Ph.D. Candidate, NCPGG, The University of Adelaide

The search for suitable sites for carbon dioxide sequestration - the
 Jurassic-Cretaceous succession in the Petrel Sub-basin, NW Australia

 Australia has made a commitment under the terms of the Kyoto Protocol to
 reduce greenhouse gas emissions to 8% above the 1990 baseline by the years
 2008-2012.  To meet its targets, solutions need to be found to reduce
 greenhouse gas emissions released to the atmosphere.  One option under
 consideration is the geological sequestration of carbon dioxide in deep
 unused saline aquifers.  GEODISC (GEOlogical DISposal of Carbon dioxide) is
 a large collaborative research program designed to investigate the
 technological, environmental and commercial feasibility of the geological
 sequestration of carbon dioxide in Australia.  Following on from the
 regional studies of Project 1 (conducted by AGSO), Project 2 is focussing
 in on specific site locations and developing detailed geological models.
 The Plover Formation and Sandpiper Sandstone of the Petrel Sub-basin have
 been selected for a pilot study, to assess their potential as reservoirs
 for CO2 sequestration.  The Early to Late Jurassic Plover Formation
 consists of laterally extensive, multi-layered, non-marine to coastal
 sandstones, up to 500m thick.  The seal for this potential reservoir are
 the siltstones of the Frigate Formation.  Above the Frigate Formation, the
 latest Jurassic to earliest Cretaceous Sandpiper Sandstone is the second
 potential reservoir, consisting of up to 300m of laterally extensive,
 multi-layered, progradational sandstones.  The overlying Bathurst Island
 Group provides a thick regional seal of mudstones and siltstones.  2D
 seismic, well logs and core samples have been collected for reservoir
 characterisation and interpreted within a sequence stratigraphic context.
 The results so far have indicated that the potential reservoirs are complex
 and heterogeneous, which may prove useful in hindering the progress of the
 CO2 through the reservoirs.  This work will provide the basis for many of
 the other projects of the GEODISC program, which ultimately aims to
 document and evaluate the potential of four or five sites around Australia
 in terms of their geology, engineering requirements, economics and risk

 Biography of the Speaker
 Catherine Gibson-Poole graduated from Royal Holloway University of London
 (UK) with a B.Sc. (Honours) in geology in 1995 and from the University of
 Southampton (UK) with an M.Sc. in Micropalaeontology in 1996.  She then
 worked for two years as a geologist with consulting company Gaffney Cline &
 Associates, where she gained rapid international experience in geological
 models, reserves estimation and petrophysics, and also commercial
 experience of flotation, acquisition and unitisations.  Following her
 emigration to Australia in late 1998, she worked for a year with Santos
 Ltd. in the department of Corporate Development, which dealt with the
 company's acquisitions and divestments.  Catherine joined the National
 Centre for Petroleum Geology and Geophysics (NCPGG) in early 2000 to study
 for a Ph.D.  She is working on Project 2 of the APCRC's GEODISC program
 (under the supervision of Associate Professor Simon Lang), producing
 detailed geological models of two specific potential sites for CO2