Mark Lisk

Constraining the oil charge history of the South Pepper oilfield from the analysis of oil-bearing fluid inclusions

Abstract The South Pepper oilfield, located in the Barrow Sub-basin on the NW margin of the Australian continent, has experienced a multi-phase charge history. Abundant oil-bearing fluid inclusions are present in samples from within the current gas cap, suggesting that an oil column existed prior to gas. This palaeo-oil (gas-leg FI oil) has Ts/Tm and C29/C30 αβ hopane ratios of ∼1 and the C35 homohopanes are a significant proportion of the extended homohopanes. It has lower Pr/Ph and diasterane/sterane ratios than the currently reservoired live oil and contains gammacerane, a series of peaks tentatively identified as C30 to C34 17α(H)-30-norhopanes and a large amount of 2α-methylhopanes. Collectively, geochemical analysis of the gas-leg FI oil suggests that it was generated from a less mature, more calcareous source rock, deposited under more reducing conditions than the Upper Jurassic Dingo Claystone, the main source of the live oil. In addition the presence of C30 dinosteranes in the gas-leg FI oil provides a Triassic or younger age constraint. This makes Palaeozoic carbonates an unlikely source. Possible source intervals for the gas-leg FI oil are thin, Lower Jurassic limestones and marls which occur at the base of the Lower Dingo Claystone, or a thin limestone unit (the Cunaloo Member) at the base of the Triassic Locker Shale. Samples from within the present oil-leg also contain abundant oil inclusions, consistent with high oil saturations at the present day. However, these oil inclusions exhibit different fluorescence colours, suggesting they represent a second oil charge. Geochemically the oil-leg FI oil has an intermediate composition between the live oil and the gas-leg FI oil, suggesting that gas charge displaced the first oil charge, samples of which were preserved as fluid inclusions in the oil-leg sample. Biodegradation of the first oil charge, indicated by the presence of 17α(H)-25-norhopanes in the currently reservoired live oils, can be attributed to the ingress of meteoric waters, probably during sub-aerial exposure of the basin margin during Miocene wrenching. Changing environmental conditions curtailed bacterial activity and allowed unaltered oil sourced from the Dingo Claystone to accumulate below the gas cap and mix with the biodegraded residues of the first oil charge to achieve the live oil composition. The biodegradation event must have preceded the second charge as the live oil contains compounds such as n-alkanes which would have been removed had alteration occurred after the second charge. Complex charge histories are common and the analysis of palaeo-oils trapped within fluid inclusions provides the opportunity to achieve a more comprehensive assessment of hydrocarbon charge

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.

Enhanced hydrocarbon leakage at fault intersections: an example from the Timor Sea, Northwest Shelf, Australia

Abstract Three-dimensional (3D) numerical modelling of a fault intersection, similar to that suggested being the primary control onhydrocarbon leakage from the Skua Oil Field, Timor Sea, demonstrates that a zone of high dilation can be generated in the vicinity of the intersection during contraction. Only a small amount of deformation was required to initiate these dilational zones, which would probably contain high concentrations of open fractures ideal for high fluid flux in a natural system. The fault intersection was also shown to be an area of relatively low shear strain, which may enhance the potential for fluid flow at these sites due to reduced fault gouge production. Large volumes of hydrocarbons could potentially be lost from these zones of high dilation and low shear where they breach the seal. Therefore, predicting and/or identifying zones of enhanced structural permeability of this type may be critical to accurately assess the integrity of a trap.

Organic compounds trapped in aqueous fluid inclusions

Fluid inclusion samples from several Australian oil wells have been analysed to document the prevalence and composition of volatile hydrocarbons contained within aqueous inclusions. These results clearly establish that trapped palaeo formation waters can be a source of such compounds, which are frequently predominant in samples with a low content of oil-bearing inclusions. The apparent “anomalous” hydrocarbon distributions derived from aqueous inclusions contain abundant water-soluble compounds, such as benzene and toluene, which may originate from interaction of formation waters with subsurface petroleum accumulations. Aqueous inclusions are also often enriched in alkenes and oxygenated species, such as furan, which are minor constituents of petroleum but could form via secondary processes such as anoxic microbial degradation in formation waters. The co-occurrence of aqueous-derived organic compounds within samples containing oil inclusions suggest the need for caution when interpreting volatile hydrocarbon distributions. However, the presence of these components in samples from dry wells could be used as a tool to substantiate the proximity of a petroleum accumulation in an area which would otherwise be considered to have low prospectivity.

Hydrocarbon charge history of the northern Londonderry High: Implications for trap integrity and future prospectivity

Re-appraisal of the oil charge history of the northern Londonderry High has identified numerous palaeo-oil columns of up to 80 m in height. An integration of the oil charge history, stress field analysis and contemporary seepage data allows a subdivision of the well results into three distinct provinces. These each have distinct charge histories that reflect differences in potential source kitchens and all have been adversely affected by the Neogene collision of the Australian and Southeast Asian plates. Traps located on the northern and northeastern Londonderry High have experienced high oil charge rates at the Mesozoic level, with nearly all valid traps showing evidence of prior oil accumulation. Breaching of these oil columns in the Neogene appears to be related to the orientation of the contemporary stress field, which promotes shear failure on the faults reliant for seal. Present day hydrocarbon migration indicators, such as Synthetic Aperture Radar (SAR) data show differences in seepage response between the northern and northeastern Londonderry High, with prolific current day seepage restricted to the northern province. Rapid subsidence associated with plate collision has accelerated maturation in the northern province to create these strong seepage anomalies over this region. The absence of seepage over the breached oil columns of the northeastern province indicates that either, oil charge has ceased to this area or that hydrocarbon leakage is episodic in nature. In contrast, results from the northwestern province show no evidence of prior oil accumulation, despite many wells having tested valid traps. These data point to either a lack of connected oil migration pathways or an impoverished source kitchen for liquid hydrocarbons. Low levels of seepage in the northwestern Londonderry High detected by the SAR data are minor compared with other parts of the Timor Sea and consistent with migration continuing at the current day. The overall prospectivity for fault bound traps in the study area appears to be low, due to extensive fault reactivation producing low fault seal integrity. Stratigraphic plays that do not rely on faults for seal, particularly in the northern and northeastern provinces, represent an alternative play concept at the Jurassic level. At shallower levels in the Cretaceous, subtle four-way dip closed structures are often enhanced by the reactivation process and could be ideally positioned to receive remigrated oil from breached Jurassic oil accumulations.

Transient fluid flow in the Timor Sea, Australia: implications for prediction of fault seal integrity

Abstract A variety of geochemical techniques have been used to identify vertical remigration of oil and saline formation water from Mesozoic hydrocarbon traps in the Timor Sea, Northern Australia. This transient fluid flow event is thought to have been initiated by the Mio-Pliocene fault reactivation and has a major impact on the seal integrity of fault dependant hydrocarbon traps. Significant thermal anomalies appear to accompany brine flow and together with the highly saline nature of the fluids and absence of a shallow salt source suggest that these originate from deeply buried Palaeozoic evaporites. Numerical simulations have been utilised to test this hypothesis, and in combination with the empirical observations seek to provide an enhanced prediction of fault seal integrity for future exploration.