Hydrocarbon charge in the onshore Canning Basin: insights from quantitative fluorescence and fluid inclusion investigations

2011 ◽  
Vol 51 (2) ◽  
pp. 706
Author(s):  
Keyu Liu ◽  
Ameed Ghori ◽  
Richard Kempton ◽  
Peter Eadington ◽  
Stephen Fenton ◽  
...  
Keyword(s):  
Fluid Inclusion ◽  
Petroleum System ◽  
Spectral Signature ◽  
Depth Interval ◽  
Widespread Occurrence ◽  
Canning Basin ◽  
Group A ◽  
Multiple Reservoir ◽  
Hydrocarbon Charge ◽  
Quantitative Fluorescence

The vast and mostly onshore Canning Basin—with an area of approximately 595,000 m2—is the least explored onshore sedimentary basin in Australia. As part of the petroleum system assessment carried out by WA DMP, more than 160 samples were investigated from eight wells in the onshore Canning Basin—they are: Acacia-1 Dodonea-1 Dodonea-2 Lake Hevern-1 Looma-1 White Hill-1 Wilson Cliffs-1 Yulleroo-1. Fluid inclusion and quantitative fluorescence techniques developed by CSIRO were used, including: The grains containing oil inclusions (GOITM) technique; The quantitative grain fluorescence (QGF) technique; QGF on extracts (QGF-E); and, the total scanning fluorescence (TSF) technique. The results reveal a widespread occurrence of hydrocarbon shows in the reservoir intervals investigated—7–8 wells showed evidence of oil migration and/or accumulations often occurring at multiple depth intervals. In White Hill-1, elevated QGF and QGF-E responses were recorded in the sandy units in a depth interval of more than 500 m in the Fairfield Group. A residual or palaeo oil column of >20 m gross height at 1,655 m was apparent from the QGF and QGF-E depth profiles—and GOI and TSF data. Oil inclusions from the Fairfield Group in White Hill-1 show spectral signature typical of thermally mature and light-medium API gravity. The TSF results also indicate the presence of some condensate species, as well as relatively heavy and possibly bio-degraded oils. The new fluid inclusion and fluorescence data provide direct evidence of an active petroleum system in the Canning Basin at multiple reservoir intervals, which may be of local significant quantity.

Detection of palaeo-oil columns in the offshore northern Perth Basin: extension of the effective Permo-Triassic charge system

2011 ◽  
Vol 51 (1) ◽  
pp. 377 ◽  
Author(s):  
Richard Kempton ◽  
Se Gong ◽  
John Kennard ◽  
Herbert Volk ◽  
David Mills ◽  
...  
Keyword(s):  
Fluid Inclusion ◽  
Geochemical Data ◽  
Terrestrial Organic Matter ◽  
Oil Accumulation ◽  
Charge System ◽  
High Incidence ◽  
Turtle Dove ◽  
Wax Content ◽  
Tricyclic Terpanes ◽  
Hydrocarbon Charge

A widespread charge system for oil accumulation in the offshore northern Perth Basin, Western Australia, is revealed by specialised fluid inclusion technologies. Palaeo-oil columns are detected in about three of four exploration wells, including those at the Cliff Head, Dunsborough, Frankland and Perseverance fields, and in dry wells at Flying Foam–1, Hadda–1, Houtman–1, Leander Reef–1, Lilac–1, Livet–1, Mentelle–1 and Morangie–1. A high incidence of palaeo-oil charge into Permian reservoirs below the Kockatea Shale confirms that the conventional oil shows are, in part, residues of palaeo-oil. Oil migration is suggested at Vindara–1 and Leander Reef–1 and is below detection limits in Batavia–1, Charon–1, Fiddich–1 Geelvink–1A, Gun Island–1 and South Turtle Dove–1B, Twin Lions–1 and Wittecarra–1. New geochemical data from fluid inclusion oil at Hadda–1 shows evidence for a contribution from the Hovea Member of the Kockatea Shale, including: high wax content; low pristane/phytane ratio; high abundance of extended tricyclic terpanes; and, the highly diagnostic C33 n-alkylcyclohexane biomarker. This key component of the petroleum system acted as both source and seal, and extends further offshore than previously realised. Possible co-sourcing from terrestrial organic matter is indicated by high abundances of C29 steranes and diasteranes, C19 tricyclic, and C24 tetracyclic terpanes, which may be sourced from Permian rocks. The high incidence of palaeo-oil and residual columns suggests that trap integrity is likely to be an important preservation risk, with elements of gas displacement. Screening of prospects for structural and hydrocarbon charge characteristics, which are favourable for retention of oil, is key in future exploration of the offshore northern Perth Basin.

OIL MIGRATION HISTORY OF THE OFFSHORE CANNING BASIN

2000 ◽  
Vol 40 (2) ◽  
pp. 133 ◽  
Author(s):  
M. Lisk ◽  
J. Ostby ◽  
N.J. Russell ◽  
G.W. O’Brien
Keyword(s):  
Fluid Inclusion ◽  
Acid Leaching ◽  
Reservoir Quality ◽  
Oil Migration ◽  
North West ◽  
Canning Basin ◽  
Carbonate Cement ◽  
Migration History ◽  
Potential Reservoir ◽  
Porosity And Permeability

The dual issues of the presence or absence of a viable, oil-prone petroleum system and reservoir quality represent key exploration uncertainties in the lightly explored Offshore Canning Basin, North West Shelf. To better quantify these factors, a detailed fluid inclusion investigation of potential reservoir horizons within the basin has been undertaken. The results have been integrated with regional petroleum geology and Synthetic Aperture Radar (SAR) oil seep data to better understand the oil migration risk in the region.The fluid inclusion data provide confirmation of widespread oil migration at multiple Mesozoic and Palaeozoic levels, including those wells that are remote from the likely source kitchens. The lack of evidence for present or palaeo-oil accumulations is consistent with the proposition that none of the currently water-wet wells appear to have tested a valid structure. These observations, when combined with the presence of numerous direct hydrocarbon indicators on seismic data and a number of oil slicks (from SAR data) at the basin’s edge, suggest that the potential for oil charge to valid structures is much higher than previously recognised.Petrographic analysis of the tight, gas-bearing, Triassic sandstones in Phoenix–1 suggests that the low porosity and permeability is the result of late poikilotopic carbonate cement. Significantly, the presence of oil inclusions within quartz overgrowths that pre-date the carbonate indicates that oil migration began prior to crystallisation of carbonate. Fluid inclusion palaeotemperatures combined with a 1D basin model suggest that trapping of oil as inclusions occurred in the Early to Middle Cretaceous and that predictions of reservoir quality using available water-wet wells could seriously under-estimate porositypermeability levels in potential traps that were charged with oil at about 100 Ma. Indeed, acid leaching of core plugs from Phoenix–1 indicates that removal of diagenetic carbonate results in significant permeability increase with obvious implications for the producibility of any future oil discovery. Further, evidence of Early Cretaceous oil charge has implications for the size and locality of source kitchens compared to that observed at the current day.Collectively, the data indicate the area has received widespread oil migration and suggest future exploration, even to relatively deep levels, may be successful if valid traps can be delineated.

Advanced methods for the evaluation of a hybrid-type unconventional play: The Bakken petroleum system

2016 ◽  
Vol 4 (2) ◽  
pp. SF93-SF111 ◽  
Author(s):  
Iain Pirie ◽  
Jack Horkowitz ◽  
Gary Simpson ◽  
John Hohman
Keyword(s):  
Evaluation Methods ◽  
Petroleum System ◽  
Oil Field ◽  
Probabilistic Methods ◽  
Rock Properties ◽  
Depth Interval ◽  
Free Fluid ◽  
Formation Evaluation ◽  
Hybrid Type ◽  
Petrophysical Evaluation

Hybrid-type plays such as the Bakken petroleum system (BPS) can be particularly challenging from an interpretation, completion, or production perspective due to the mix of conventional and unconventional elements coexisting within a relatively short depth interval. In the BPS, conventional aspects include the presence of separate reservoir intervals, which, depending on your location within the basin, may include the Scallion, Middle Bakken, Sanish, and Three Forks. Unconventional aspects include the Lower Bakken and Upper Bakken shales, which are organic-rich shales comprising source rock and reservoir. Developing an accurate petrophysical evaluation of these formations requires a priori knowledge of the mineralogy, fluids, and geomechanical properties such that appropriate logging measurements, core analysis methods, and interpretation techniques can be obtained and used. During the development phase of an oil field, the log and core measurements being acquired and the petrophysical evaluation being performed may vary significantly from well to well across the field. Some wells may have triple-combo wireline or logging-while-drilling measurements consisting of bulk density, neutron porosity, and induction or laterolog resistivity, supplemented with a total gamma ray measurement. Borehole sonic logs may also have been acquired in some wells primarily for seismic calibration, geomechanical modeling, and hydraulic stimulation design. If the “standard” suite of measurements and petrophysical evaluation being provided fail to accurately represent the true complexity of the formations being evaluated, the asset valuation will, in most cases, be negatively impacted. Our formation evaluation of the BPS led to the identification of unique petrophysical challenges for each of the formations comprising the BPS. Traditional formation evaluation methods were applied to the BPS based on triple-combo measurements, a traditional petrophysical analysis, and the evaluation of net feet of pay. Advanced evaluation methods and techniques were then applied to address the petrophysical complexities identified with core evaluation, advanced log measurements, and discrepancies between the two. New petrophysical models were developed and fine-tuned to address the shortcomings of the simple models, and the net feet of pay were reevaluated using these new models. The detailed formation evaluation program used to characterize the BPS consisted of standard triple-combo logs supplemented with advanced downhole measurements including: (1) triaxial resistivity for thin-bed analysis, (2) nuclear magnetic resonance for porosity, free-fluid, and kerogen identification, (3) dielectric dispersion for water saturation, (4) geochemical spectroscopy for mineralogy and total organic carbon, and (5) dipole sonic for dynamic rock properties. Petrophysical models were developed using deterministic and probabilistic methods to integrate the measurements acquired for the most accurate analysis of porosity, saturation, and mineralogy and to best describe the hydrocarbon production potential of the BPS.

Hydrocarbon charge history of the Gippsland Basin

2010 ◽  
Vol 50 (2) ◽  
pp. 729
Author(s):  
Keyu Liu ◽  
Peter Eadington ◽  
David Mills ◽  
Richard Kempton ◽  
Herbert Volk ◽  
...  
Keyword(s):  
System Analysis ◽  
Evaluation Research ◽  
Petroleum System ◽  
Additional Information ◽  
Oil Generation ◽  
History Of ◽  
And Migration ◽  
Hydrocarbon Charge ◽  
Gas Fields ◽  
Gippsland Basin

As part of a larger petroleum system analysis and resource re-evaluation research program in the Gippsland Basin, over 400 samples from 29 selected wells in the Gippsland Basin were investigated using quantitative fluorescence techniques developed by CSIRO Petroleum, including the quantitative grain fluorescence (QGF) and QGF on extracts (QGF-E) and the total scanning fluorescence (TSF) techniques. Preliminary results have provided new insight into the hydrocarbon migration and charge history of the Gippsland Basin. The investigation has revealed: widespread occurrence of palaeo oil columns in some of the major gas fields, indicating that a significant amount of oil was charged into these reservoirs prior to a subsequent gas accumulation; that some of the current oil intervals appear to have received a relatively late oil charge, either through new charge or through palaeo oil re-distribution due to adjustments within the petroleum system; palaeo oil columns appear to be restricted to a certain distance range from the major source kitchens; and, evidence of a sequential oil migration and displacement along structural highs where reservoirs distal to the source kitchens received progressively lighter and more mature palaeo oils. These findings are consistent with the oil generation and migration model proposed by O’Brien et al (2008). Fluid inclusion petrographic investigations and molecular composition of inclusions (MCI) analysis are currently underway that will provide additional information on the hydrocarbon charge history in the Gippsland Basin.

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