Peter Eadington

Assessing the maturity of oil trapped in fluid inclusions using molecular geochemistry data and visually-determined fluorescence colours

Abstract The thermal maturity of oils extracted from inclusions and the fluorescence colours of oil-bearing fluid inclusions have been measured in 36 sandstone samples from Australasian oil fields. The inclusion oils were analysed using an off-line crushing technique followed by GC–MS. A maturity assessment was made for each inclusion oil using 25 molecular maturity ratios, including a newly defined dimethyldibenzothiophene ratio (DMDR). Each inclusion oil was placed in one of 4 maturity brackets, approximately equivalent to early, mid, peak and post oil generation windows. The fluorescence colours of oil inclusions were visually-discriminated into “blue”, “white” and “yellow plus orange” and their proportions estimated using point counting techniques. Sixteen samples have >85% of oil inclusions with blue fluorescence, whilst other samples have more variable fluorescence colours. One sample has 100% of oil inclusions with yellow plus orange fluorescence. The results show that samples containing mainly blue-fluorescing oil inclusions have thermal maturities anywhere within the oil window. In particular, the molecular geochemical data strongly suggests that oil inclusions with blue fluorescence can have relatively low maturities (calculated reflectance

Quantitative evaluation of the oil-leg potential in the Oliver gas field, Timor Sea, Australia

Oil-bearing fluid inclusions in sandstone cores and cuttings represent hidden oil shows. The frequency of quartz grains containing these inclusions (the GOI number) reflects the maximum paleo-oil saturation experienced in a sandstone reservoir irrespective of the present fluid phase. Samples that have been exposed to high oil saturation have GOI numbers at least one order of magnitude greater than samples that have demonstrably low oil saturation. In this way, these fluid inclusion data can be used to identify paleo-oil columns and to map original oil-water contacts in wells where oil has been displaced by a later gas charge. Moreover, the use of detailed GOI mapping to accurately define the location of the original oil-water contact allows the height of the paleocolumn to be determined and an estimate to be made of original oil in place. The Oliver oil and gas discovery, located in the Timor Sea, Australia, presently contains a hydrocarbon column of 178.5 m, composed of 164 m of gas over a 14.5 m oil leg, and is filled to spillpoint. In well Oliver-1, GOI mapping has delineated a gross paleo-oil column of between 99 and 132 m within the present gas leg. This corresponds to original oil in place of up to 200 million bbl, considerably greater than the 45 million bbl of oil presently reservoired. The displacement of up to 155 million bbl of oil from this structure has high-graded the prospectivity of tilted fault blocks updip from the Oliver structure. GOI mapping is an innovative approach to reservoir characterization that can reliably detect paleo-oil accumulation in hydrocarbon traps that are presently filled by gas. These data allow the oil-leg potential of both gas discoveries and nearby untested structures to be addressed in a quantitative manner before additional drilling is commissioned.

Evidence for the magmatic origin of quartz-topaz rocks from the New England batholith, Australia

Quartz-topaz rocks from the New England district, New South Wales, have mineralogical, textural and field relationships suggesting a magmatic origin. These rocks (called topazites) occur as dykes and sills intruding a biotite granite and sediments in a roof pendant. Where they have intruded into sediments, the topazites have a narrow aureole of induration or hornfels. One type of primary solid inclusion, thought to be silicate glass, has a composition ranging from that of the topazite towards that of nearby granite. Primary fluid inclusions contain an aqueous solution of alkali chlorides with concentrations of total salts to 57 wt%. These fluid inclusions indicate crystallization temperatures in the range 570–620° C, close to the experimentally determined solidus of a vapour-saturated, topaz-normative melt. The presence of primary fluid inclusions indicates crystallization of topazite following saturation of a granitic magma with water and the formation of immiscible silicate and aqueous phases. Partitioning of alkali metals into the aqueous phase left a silicate melt that could only crystallize quartz and topaz.

Fluorescence evidence of polar hydrocarbon interaction on mineral surfaces and implications to alteration of reservoir wettability

Abstract Petrographic analysis of reservoir rocks in an apparently water-wet system under UV light indicates the ubiquitous presence of microscopic oil inclusions within quartz grains. The micro-sized inclusions are often trapped along healed micro-fractures or along quartz overgrowth boundaries. The apertures of the micro-fractures are usually a few microns in width, an order of magnitude smaller than the typical pore aperture (throat) of reservoir rocks. When these same reservoir rocks were analysed using a highly sensitive fluorescence spectrophotometer after series of cleaning steps using solvents and oxidizing agents, it was revealed that polar organic compounds are present on quartz grain surfaces. Examination of the quartz grain surface using scanning electron microscope (SEM) and an energy dispersive X-ray (EDAX) system confirmed the presence of fine residual hydrocarbon particles associated with clay minerals coated on the highly irregular quartz grain surface. The presence of polar organic compounds and/or asphaltenes on water-wet quartz surfaces results in wettability alteration under reservoir conditions, which may allow direct contact between hydrocarbon and the water-wet quartz grains, resulting in the formation of micro-size oil inclusions in quartz grains.

Petroleum Hydrogeology of the Cooper and Eromanga Basins, Australia: Some Insights from Mathematical Modeling and Fluid Inclusion Data

Mathematical modeling and fluid inclusion data analysis are used to reconstruct the petroleum hydrogeology of the Australian Cooper and Eromanga basins. Our analysis focuses on the development of topography- and compaction-driven groundwater flow systems and their role in heat redistribution, petroleum generation, and oil and brine migration during basin evolution. Finite-element models of basin transport processes are constructed along northeast-southwest (AA´) and northwest-southeast (BB´) cross sections that generally follow the present-day groundwater flow patterns through these basins. Numerical results are presented in the ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received September 19, 1995; revised manuscript received July 3, 1996; final acceptance November 11, 1996. 2Independent Consultant, 12 Rinzee Road, Dracut, Massachusetts 01826. 3CSIRO Division of Petroleum Exploration, 51 Delhi Road, North Ryde, NSW 2113, Australia. 4Department of Geology and Geophysics, University of Minnesota, 310 Pillsbury Drive SE, Minneapolis, Minnesota 55455 (E-mail: mperson@ darcy.geo.umn.edu) 5GZA GeoEnvironmental Inc., 380 Harvey Road, Manchester, New Hampshire 03103. 6Santos Ltd., 101 Grenfell Street, Adelaide, SA 7000, Australia. This research is supported by a grant from the Petroleum Research Fund, administered by the American Chemical Society, PRF 24184-AC8. We would also like to acknowledge the Orpha and George Gibson Hydrogeology Endowment and the McKnight Land-Grant Professorship Program at the University of Minnesota. We thank the CSIRO Division of Exploration Geosciences for providing support for travel costs within Australia. Data provided by Santos Ltd. and the Department of Mines and Energy, South Australia, are also gratefully acknowledged. Computational work performed on this project was done at the Gibson Computational Hydrogeology Laboratory at the University of Minnesota, which is supported by the National Science Foundation under EAR 94-05807. Special thanks go to M. A. Habermehl of the Australian Geological Survey Organization, David Gravestock of the South Australia Bureau of Mines and Mineral Resources, and Mike Congreves of Santos Ltd. for their assistance on interpreting the petroleum geology and hydrogeology of the Cooper and Eromanga basins. The review comments of Joseph Toth, Stefan Bachu, and Michelle Walvoord, as well as discussions with Ward Sanford, greatly improved the quality of this manuscript. Three-dimensional model results presented in this paper are available in animated form on VHS videocassette and can be obtained by contacting Mark Person at the address listed for him as the corresponding author.

Reply to comment by Oxtoby on “Assessing the maturity of oil trapped in fluid inclusions using molecular geochemistry data and visually-determined fluorescence colours”

The authors welcome the opportunity to respond to some of the comments of Oxtoby (2002) regarding their recent paper (George et al., 2001). We will respond to the two main topics that have been raised by Oxtoby (2002): firstly the petrological procedures used, and secondly the possible causes for the wide maturity range of blue fluorescing oil inclusions. The issue of the relationship of fluorescence colour and API gravity raised by Oxtoby (2002) was not discussed in the paper.

A new method for identifying secondary oil migration pathways

Abstract A method called Oil Migration Intervals (OMI) is presented to assist identifying lateral oil migration pathways intersected inexploration boreholes. It predicts potential profiles of residual oil saturation due to partial confinement of oil below sealing strata using a pseudodisplacement pressure log and the buoyancy gradient. The OMI method performs calculations on wireline log data and uses empirical correlations between permeability and displacement pressure to derive a continuous pseudodisplacement pressure log for an intersection of reservoir or carrier bed. A pseudopermeability log is calculated from a modified Wyllie-Rose equation by replacing the irreducible water saturation factor with an empirical pore aperture parameter utilising V -Shale and Porosity. The pseudodisplacement pressure is subtracted from the buoyancy gradient to obtain profiles of potential excess buoyancy pressure and thus relative residual oil saturation due to partial confinement beneath sealing strata. The OMI log can then be directly compared with scaled field or laboratory measured oil show indicators to identify genuine secondary (lateral) oil migration. The steps in the calculation of the OMI log have been calibrated using laboratory and field data from exploration oil wells in the Timor Sea, NW Shelf, Australia.

The effect of temperature of reaction on the extraction of tin from calc-silicate rocks by NH4I volatilisation

Abstract Extraction of lattice-bound tin from calc-silicate minerals in the determination of tin in skarn rocks by NH 4 I volatilisation is reported. This analytical technique has previously been regarded as specific for cassiterite and stannite. Although the NH 4 I volatilisation reaction does not decompose calc-silicate minerals there is an increase in the yield of NH 4 I-volatilised tin when the volatilisation temperature is raised above 500°C. The temperature effect is only observed for whole-rock samples and the type of behaviour appears related to the mineralogy of the rock. For instance, magnetite-bearing rocks have a different temperature yield curve to pyrrhotite-bearing rocks. When concentrates of single minerals are reacted with NH 4 I this temperature dependence is not observed, although there is an increase in tin yield with decreasing grainsize.

Quantitative Modeling and Three-Dimensional Visualization of the Petroleum Hydrogeology of the Cooper and Eromanga Basins, Australia: ABSTRACT

Mathematical modeling and three-dimensional scientific visualization techniques are used in this study to reconstruct the petroleum hydrogeology of the well-studied Cooper and Eromanga Basins: Australia`s most productive on shore petroleum provinces. Our analysis focuses on the development of topography- and compaction-driven groundwater flow systems and their role on petroleum generation and migration within these basins. Finite-element models which represent groundwater flow, heat transfer, oil generation and migration were constructed along NW-SE and NE-SW cross-sectional transacts which more or less follow the present-day groundwater flow patterns through these basins. The analysis provides a quantitative reconstruction of transient fluid migration in response to tectonic processes during the past 276 million years of basin evolution. In order to compress numerical output from both cross-sectional models into a single image, quantitative results are presented in the form of evolving, three- dimensional geologic fence diagrams. Computer animation of numerical model results permit analysis of transient hydrodynamic behavior within the basin that would have been difficult or impossible to detect otherwise. Analysis of video output indicates that two episodes of regional, topography-driven groundwater flow had a pronounced effect on the thermal history of the sediments and may have important implications for petroleum generation and migration.