Early Oil Charge Research Articles

Exhumation filling and paleo-pasteurization of the shallow petroleum system in the North Slope of the Biyang Sag, Nanxiang Basin, China

Deposits of biodegraded heavy oils are commonly encountered within the Eocene reservoir units in the North Slope of the Biyang Sag, Nanxiang Basin, eastern China. Oil physical property data and biomarkers show that these biodegraded oils occur only above burial depth equivalent to about 62 °C. This is much cooler than the cutoff temperature of biodegradation (about 80 °C), which has been interpreted within a complex petroleum evolution history that includes an early oil filling, significant uplift, a second phase of filling, and late-stage biodegradation.We use a new combination of fluid-inclusion analysis and calcite LA-ICP-MS U–Pb dating to obtain a temporal constraint on oil migration in the siliciclastic reservoirs. Two generations of oil inclusions, each showing a distinct fluorescence color (yellow and blue-green), were trapped before and after quartz cementation, respectively, which indicates multi-stage oil charge events. The early oil charge, marked by hydrostatic conditions and low-salinity pore waters, occurred during the late Eocene to early Oligocene burial period, corresponding to peak oil generation by basin modeling. The reservoirs were then refilled at a moderate-overpressure regime by higher maturity oils accompanied by high-salinity waters during the early Miocene exhumation. Reservoir sandstone-hosted, yellowish calcite veins, characteristic of 13C depletion and oil odor, contain primary blue-green fluorescent oil inclusions and bitumens, consistently pointing to precipitation from petroleum-derived fluids. LA-ICP-MS U–Pb dating of these vein calcites yields a U–Pb age of 19.6 ± 1.2 Ma, representing the latest timing of the second oil charge event in the North Slope. The isotope age of the fissure calcites near fault zones coincides well with the indirect age estimate based on fluid-inclusion homogenization temperature and the regional uplift stage. This scenario suggests that the Miocene tectonic compression not only triggered the recharge of oils but also facilitated the initiation or re-activation of faults that acted as conduits for oil migration.Reconstructed burial models show a continuous burial followed by significant uplift and erosion in this region. Since some reservoirs with maximum paleotemperature less than 80 °C were not sterilized during burial, the contained oils suffered from extensive biodegradation, presumably during the middle Miocene to present day. Thus, the shallower shutoff depth of biodegradation in this region was most likely ascribed to the paleo-pasteurization during burial, as opposed to later fresh oil replenishment or influx of shallow aquifers.

The Birgitta Field, Block 22/19a, UK North Sea

Abstract Birgitta Field was discovered by well 22/19-1 which encountered a 230 ft gas–condensate column in Triassic Skagerrak Formation and tested at a combined rate of 38.3 MMscfgd and 3750 bcpd. The tilted-fault block trap forms the crest of a Triassic ‘pod’ or mini-basin formed by salt withdrawal during Triassic extension, further rotated and eroded during Jurassic extension. Field extent is supported by apparent seismic hydrocarbon indications. An early oil charge was likely converted to condensate by Plio-Pleistocene gas influx and rapid burial, whilst an underlying palaeoresidual gas column reflects some trap leakage. Birgitta typifies certain Triassic reservoir characteristics in this part of the Central North Sea. The thick, relatively high net:gross reservoir comprises moderate to poorly sorted, sub-lithic to sub-arkosic sandstones deposited in a dryland braided fluvial system. Pore-lining chlorite overgrowths dominate the pore fabric, reducing pore throat sizes and contributing to appreciable levels of non-effective micro-porosity and hence elevated water saturation. Key petrophysical challenges are the accurate determination of effective porosity and water saturation. Birgitta approaches high pressure–high temperature conditions and illustrates some of the challenges of progressing small, unappraised field tie-backs. These include resource uncertainty, compartmentalization risk, infrastructure access and marginal economics. Evaluated for development several times, Birgitta presently remains undeveloped.

The origin and accumulation of multi-phase reservoirs in the east Tabei uplift, Tarim Basin, China

Abstract A giant deep-strata oil-gas field with complex fluid characteristics was recently discovered in the Hade-Yuke area of the east Tabei uplift (Tarim Basin, NW China). The deep fluids show a lateral co-existence of several gas, condensate and oil phase reservoirs characterized through the integration of complimentary geochemical (e.g., bulk composition, biomarker and stable carbon isotope) and geological data. Typical features of the gas and condensate reservoirs, which were mainly distributed in the eastern parts of the study site, included high GOR (gas-to-oil ratio), hydrocarbon gases with relatively heavy δ13C values and crude oils with high wax content. In contrast oil reservoirs, which mostly occurred in more westerly locations, had lower GOR values, lighter δ13C values and lower wax content, indicating gradual change of fluid characters. The petroleum accumulations derive from two hydrocarbon charge events: an early oil charge in the Late Hercynian and a later gas charge in the Late Himalayan which migrated from east to west, leading to a gradual variation in fluid phase and characteristics. Alteration of paleo oil reservoirs by this secondary gas charge was therefore primarily responsible for the complex fluid character and multi-phase reservoirs presently in place. Secondary condensates were formed from the retrograde condensation of paleo reservoirs. Our re-construction of the hydrocarbon accumulation process encourages future exploration endeavours to target commercially viable gas accumulations in the deep east strata and oil reservoirs in the west.

Effects of early oil emplacement on reservoir quality and gas migration in the Lower Jurassic tight sand reservoirs of Dibei gas field, Kuqa Depression, western China

It is common for many tight gas sandstone reservoirs to have experienced an early oil charge before gas invading. To determine the effects of early oil emplacement on reservoir quality and gas migration has important role in predicting “sweet spots” of gas production in tight sand reservoirs. We investigated the palaeo and current fluids contacts accurately due to parameters from quantitative grain fluorescence in the Lower Jurassic Ahe Formation of Dibei gas field. The porosity and permeability values in palaeo-oil leg are totally higher than in palaeo-water leg, especially there being a wide gap of permeability with an order of magnitude. The variation of reservoir quality derives from the early oil emplacement, which restrained clay conversions from kaolinite or illite-smectite mixed-layer into fibrous illite that dramatically increasing flow-path tortuosity in sandstones, according to core analysis and X-ray diffraction. The early oil preserved penetrating quality of palaeo-oil leg, but the sandstones that never experienced early oil emplacement contains much more fibrous illite. It made most of early oil pathways subsequently act as the migration pathways for late gas and less than 50% of the migration pathways for gas were caused by microfractures due to quantitative grain fluorescence. Only the sandstones with medium early oil saturation did become sweet spots for gas in the tight sand reservoirs. Too much and too little oil once saturated in pores maybe adverse to the late gas migration and accumulation.

Hydrocarbon migration and accumulation of the Suqiao buried-hill zone in Wen'an Slope, Jizhong Subbasin, Bohai Bay Basin, China

The hydrocarbon migration and accumulation of the Suqiao deep buried-hill zone, in the Jizhong Subbasin, the Bohai Bay Basin, eastern China, was investigated from the perspective of paleo-fluid evidence by using fluid inclusions, quantitative fluorescence techniques (QGF), total scanning fluorescence method (TSF) and organic geochemical analysis. Results show that the current condensate oil-gas reservoirs in the study area once were paleo-oil reservoirs. In addition, the reservoirs have experienced at least two stages of hydrocarbon charge from different sources and/or maturities. During the deposition of the Oligocene Dongying Formation (Ed), the deep Ordovician reservoirs were first charged by mature oils sourced from the lacustrine shale source rocks in the fourth member of Shahejie and Kongdian Formations (Es4+Ek), and then adjusted at the end of Ed period subsequently by virtue of the tectonic movement. Since the deposition of the Neogene Minghuazhen Formation (Nm), the reservoirs were mainly charged by the gas that consisted of moderate to high-maturity condensate and wet gas sourced from the Es4+Ek lacustrine shale source rocks and mature coal-derived gas sourced from the Carboniferous-Permian (C-P) coal-bearing source rocks. Meanwhile, the early charged oil was subjected to gas flushing and deasphalting by the late intrusion of gas. The widely distributed hydrocarbon inclusions, the higher QGF Index, and FOI (the frequency of oil inclusions) values in both gas-oil and water zone, are indicative of early oil charge. In addition, combined with the homogenization temperatures of the fluid inclusions (<160 °C) and the existence of solid-bitumen bearing inclusions, significant loss of the n-alkanes with low carbon numbers, enrichments of heavier components in crude oils, and the precipitation of asphaltene in the residual pores suggest that gas flushing may have played an important role in the reservoir formation.

Deciphering multiple controls on reservoir quality and inhibition of quartz cement in a complex reservoir: Ordovician glacial sandstones, Illizi Basin, Algeria

Abstract Late Ordovician ( c. 445 Ma) glacial sandstones form important gas reservoirs in the Illizi Basin, SW Algeria. These reservoirs have a high degree of depositional and diagenetic complexity, such that understanding and predicting reservoir quality (RQ) presents a major challenge to their economic development. Porosity is typically 1–10%, but reaches up to 15% and permeability is typically &lt;10 −15 m 2 (&lt;1 mD), but locally reaches &gt;10 −13 m 2 (&gt;100 mD). The key questions addressed herein concern the development and distribution of this RQ variability, specifically why has good RQ been locally preserved? Primary depositional fabric exerts a strong control on RQ. Muddy sandstones are either highly compacted or pervasively cemented by quartz and microporous illite, and have very poor RQ. Only fine- to medium-grained, moderately well sorted, clean sandstones can contain good RQ, but texturally and mineralogically similar sandstones span a wide range of porosity and permeability. This range is primarily driven by the degree of quartz cementation, with incomplete cementation resulting in the best RQ. Quartz overgrowths in incompletely cemented clean sandstones are patchy and non-luminescent in scanning electron microscopy with cathodoluminescence (SEM-CL), possibly indicating slow growth rates. There is tentative evidence to link incomplete quartz cementation with oil charging of the reservoir. An alternative or additional explanation of RQ preservation may be related to limited silica supply in the centres of the thickest, stacked, clean sandstones, where the better RQ tends to reside. The results of this study imply that sustained high-energy depositional processes, coupled with an early oil charge, are prerequisites for retaining the best RQ. This has important implications for the exploration and development of Late Ordovician glacial sandstones in the Illizi Basin, and potentially similar plays elsewhere.

Medium-deep clastic reservoirs in the slope area of Qikou sag, Huanghua depression, Bohai Bay Basin

Abstract To get a better understanding of the distribution pattern of favorable reservoir belts in the medium-deep clastic rocks in the Qikou sag of the Huanghua depression, and find out premium reservoir zone, the characteristics and controlling factors of the medium-deep reservoirs in the Qikou sag were analyzed. Comprehensive study into the structural setting, provenance, depositional system, and reservoir properties shows that the Paleogene in the Qikou sag has multi-sags and multi-slopes, with slopes accounting for over 70% of the total sag area. A number of large braided river (fan) delta front - gravity flow sand bodies matching with multi-slope zones lay a good material foundation for the formation of medium-deep effective reservoirs there. Generally buried at over 2500 m, the medium-deep clastic rocks are lithic feldspathic sandstone, with secondary pores and cracks as major reservoir space. Being in the medium diagenesis evolution stage, the medium-deep clastic rocks in the Qikou sag span over a large depth. Nine major factors affecting reservoir properties have been identified by mathematical geology. Although the medium-deep clastic rock interval is poor in physical properties and complex in pore structure, high sedimentation rate, medium geothermal field, high fluid pressure, high feldspar content, relatively high dissolution rate and early oil and gas charge have given rise to three to four belts with abnormally high porosity in it, which are all favorable hydrocarbon reservoir zones.

Oil charge preserves exceptional porosity in deeply buried, overpressured, sandstones: Central North Sea, UK

Abstract: Exceptionally high-porosity sandstones are reported from oil provinces worldwide, yet the mechanism of porosity preservation remains controversial. We present strong evidence that the exceptional porosities in the Jurassic Fulmar Formation within the North Sea are the result of early oil charging preventing cementation and chemical compaction in sands with relatively low detrital clay contents, although overpressure and grain coatings do have some effect. The most dramatic evidence that reservoir quality is related to early oil charge is the spatial distribution of the porosity: the maximum porosity of the Fulmar Formation is systematically highest immediately below the top seal, and decreases below this despite uniform sedimentology. Hence, porosity is preferentially preserved where oil first accumulated in these unusually homogeneous overpressured reservoir sandstones, at the top. Oil charge prevents or significantly retards chemical compaction and cementation of a reservoir, preserving porosity. There is independent evidence for early oil charging of reservoirs within the Central Graben, from fluid inclusion studies and K–Ar age dates of authigenic illite. Micro-quartz grain coatings, which have been proposed to preserve porosity during burial, are associated with only 5% extra porosity in sands that exceed the worldwide average sandstone porosity by almost 20%.

Understanding the plumbing of the Gippsland Basin: new results on fluid migration and reservoir quality

Understanding the CO2 storage potential and petroleum prospectivity of the Gippsland Basin are critical to managing the resources of this region. Key controls on determining the prospectivity for CO2 storage and petroleum include understanding the fluid migration history and reservoir characteristics in the basin. Gippsland Basin hydrology, reservoir characteristics and petroleum systems are being studied to better understand how CO2 can be safely stored in the subsurface. Hydrocarbon migration pathways have been delineated using petroleum systems modelling. The latest hydrocarbon charge history data has been acquired to test the containment potential of individual structures along these migration pathways. The charge history results indicate the Golden Beach gas field has had a complex hydrocarbon fill history, and that early charge has migrated through the regional seal. The results also indicate that early oil charge was very common in the basin, including large structures that are now filled with gas (e.g. Barracouta). The results allow the regions with good CO2 containment potential to be delineated for further storage investigations. A new evaluation of the reservoir characteristics of the Latrobe Group—through porosity/permeability analysis and automated mineral analysis (AMA)—has provided insights into CO2 injectivity and capacity. The AMA results constrain the mineralogy and diagenetic history of the reservoirs and seals. In addition, the data highlights the presence of carbonates, glauconite and K-feldspar that are potentially reactive with injected CO2.

Petroleum systems of the oldest gas field in China: Neoproterozoic gas pools in the Weiyuan gas field, Sichuan Basin

Weiyuan, the oldest gas field in China, is a rare example of the giant Neoproterozoic gas pools. This field is located in southwestern Sichuan Basin, with a proven in place gas reserve around 40 billion cubic meters (bcm) or 1.41 trillion cubic feet (tcf) in reservoirs of the Sinian Dengying Formation. This field is almost depleted now, with a cumulative gas production of 14.4 bcm and a recovery factor of around 36%. The Neoproterozoic gas pools are also geographically overlapped by gas pools in the Lower Permian Maokou Formation, with an additional proven in place gas reserve about 0.861 bcm or 30.2 bcf. Gases in the Sinian reservoirs are relatively rich in nitrogen, CO 2, H 2S, helium and argon, with gaseous alkanes showing δ l 3C 1< δ 13C 2 and δ l3C 1< −31‰. These gases were likely derived from thermal cracking of organic matter in shales of the overlying Lower Cambrian Jiulaodong Formation. Three types of solid bitumens and hydrocarbon fluid inclusions have been identified in the Dengying reservoirs, suggesting multiple petroleum migration and accumulation events, including an early oil charge, an early gas charge, a late gas charge and a gas redistribution phase during the Caledonian, Hercynian-Indosinian, Yanshanian and Himalayan orogenies, respectively. Recent exploration of the Cambrian horizons above the established gas pools has led to significant gas discoveries in the Yuxiansi and Xixiangchi formations, thus extending the production life of this mature field.

Hydrocarbon filling and leakage history of a deep geopressured sandstone, Fulmar Formation, United Kingdom North Sea

Diagenetic minerals in a water-filled borehole from the Jurassic Fulmar Formation, United Kingdom central North Sea, record two phases of hydrocarbon filling and emptying. Initial oil charge was during the Late Cretaceous, at shallow burial depths of about 1.5 km (0.9 mi). As we consider that hydrocarbon has preserved porosity during burial, this has implications for the understanding of the porosity evolution of the Fulmar Formation, which, in other locations, is an important hydrocarbon reservoir. The early oil charge, as recorded by illite K-Ar ages, progressively filled the structure from 84 to 59 Ma, and possibly precipitated bitumen because of biodegradation. The first oil predated many of the burial diagenetic reactions within the sandstone. After leak-off at ca. 60 Ma, diagenetic reactions continued in an open geochemical system, with possible import of CO2. Products of these reactions include ankerite and quartz overgrowth cements. Hydrocarbon staining postdates these phases and provides evidence of a hydrocarbon charge, probably gas condensate. The second hydrocarbon charge also leaked off, and the sandstone is now water bearing. Previous work on the Fulmar Formation has incorrectly placed all the diagenetic reactions as predating the first arrival of hydrocarbon. The present-day pore fluids are high-salinity, high-δ18O fluids derived from the underlying Permian Zechstein evaporates. These fluids entered the reservoir during a phase of overpressure release that caused fracturing of the framework quartz grains, possibly coincident with the second phase of hydrocarbon leak-off at 2–5 Ma. Mark Wilkinson studied sandstone-hosted calcite concretions for his Ph.D. and has subsequently tried to take a more holistic view of the diagenesis of sedimentary basins. His career has been funded by a variety of oil companies, although he is currently involved in geological disposal of some of the CO2 that he was partly responsible for producing. Stuart Haszeldine is a professor at Edinburgh University. He received his Ph.D. on clastic and coal sedimentology in 1981 from the University of Strathclyde. After an attempted reeducation in the oil industry, he has collaborated with many companies to research on hydrocarbon reservoir quality, radioactive waste disposal, and coal resources. He currently heads the United Kingdom's largest group investigating carbon dioxide sequestration. Tony Fallick was educated at the University of Glasgow, Scotland, in physics (B.Sc.) and chemistry (Ph.D.). He did research at McMaster University, Ontario, Canada, and Cambridge, England, before moving in 1980 to the Scottish Universities Research and Reactor Center, where he is currently the director.

Impact of basin evolution, depositional environment, pore water evolution and diagenesis on reservoir-quality of Lower Paleozoic Haima Supergroup sandstones, Sultanate of Oman

ABSTRACTSandstones of the Early Paleozoic Miqrat Formation and Barik Sandstone Member (Haima Supergroup) are the most prolific gas/condensate containing units in the northern part of the Interior Oman Sedimentary Basin (IOSB). The reservoir-quality of these sandstones, buried to depths exceeding 5 km, is critically related to the depositional environment, burial-related diagenetic reactions, the timing of liquid hydrocarbon charge and the replacement of liquid hydrocarbon by gas/condensate.The depositional environment of the sandstones controls the net-sand distribution which results in poorer reservoir properties northwards parallel to the axis of the Ghaba Salt Basin. The sandy delta deposits of the Barik Sandstone Member have a complex diagenetic history, with early dolomite cementation, followed by compaction, chlorite formation, hydrocarbon charge, quartz and anhydrite precipitation and the formation of pore-filling and pore-lining bitumen. In the Miqrat Formation sandstone, which is comprised of inland sabkha deposits, similar authigenic minerals occur, but with higher abundances of dolomite and anhydrite, and less quartz cement. The deduced pore water evolution from deposition to recent, in both the Miqrat Formation and the Barik Sandstone Member, reflects an early addition of saline continental waters and hydrocarbon-burial related mineral reactions with the likely influx of lower-saline waters during the obduction of the Oman Mountains.Four structural provinces are recognized in the IOSB based on regional differences in the subsidence/uplift history: the Eastern Flank, the Ghaba and Fahud Salt Basins and the Mabrouk-Makarem High. In the Fahud Salt Basin, biodegradation of an early oil charge during Late Paleozoic uplift resulted in reservoir-quality degradation by bitumen clogging of the pore space. On the Eastern Flank and the Mabrouk-Makarem High, however, the early oil bypassed the area. In contrast, post-Carboniferous liquid hydrocarbons were trapped in the Mabrouk-Makarem High, whereas on the Eastern Flank surface water infiltration and loss of hydrocarbons or biodegradation to pore occluding bitumen occurred. In the Ghaba Salt Basin, post-Carboniferous hydrocarbon charge induced a redox reaction to form porosity/permeability preserving chlorite in the reservoirs. The liquid hydrocarbons were replaced since the obduction of the Oman Mountains by gas/condensate which prevented the deep parts (&amp;gt;5,000 m) of the Ghaba Salt Basin from pore occluding pyrobitumen and thus deterioration of the reservoir quality.

OIL MIGRATION HISTORY OF THE OFFSHORE CANNING BASIN

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.

Geochemical comparison of oil-bearing fluid inclusions and produced oil from the Toro sandstone, Papua New Guinea

A detailed study was carried out to compare the geochemistry of the crude oil in the Lower Cretaceous Toro sandstone reservoir in the Iagifu-7X well with oil trapped in fluid inclusions in this sandstone in the Iagifu-7X and P'nyang-2X wells in the Papuan Fold Belt. The drill stem test (DST) oils and the oils trapped in fluid inclusions show different source- and maturity-dependent geochemical parameters. Biomarkers suggest that the DST oils at Iagifu-7X were derived from clay-rich, mixed marine/terrestrial source rocks deposited under oxic conditions, probably Middle to Late Jurassic mudstones. The fluid inclusion oils were derived from a less terrestrially-influenced marine source rock deposited under less oxic conditions. The fluid inclusion oils contain 1,2,7-trimethylnaphthalene and oleanane biomarkers indicative of angiosperm input and a Cretaceous or younger source rock. These oils are more mature (calculated reflectance [ R c] = 1.02%) than the reservoired oil at Iagifu-7X ( R c = 0.84%) and condensate at P'nyang-2X ( R c = 0.84%). Source and thermal maturity parameters for all three fluid inclusion samples are similar, suggesting that they were derived from similar source rock facies. Furthermore, samples with predominantly blue vs. white fluorescing oil inclusions have no discernible geochemical maturity difference, suggesting that the use of fluorescence colours as a qualitative guide to the maturity of the trapped oil is not valid in this case. Fluid inclusion oils were trapped prior to charge of the reservoir with oil at the Iagifu-7X and gas condensate at the P'nyang-2X wells. The fluid inclusion oils therefore represent an early oil charge from a deeply buried, probably Cretaceous source rock, which started migrating into the Toro sandstone during the Miocene. At Iagifu this early oil was probably diluted by a larger volume of Jurassic oil generated at the end of the Miocene. The absence of fluid inclusions with compositions like the currently reservoired oil is interpreted to be due to oil charging an already oil-saturated zone, when diagenesis is likely to have been inhibited. At the P'nyang well, the transition from oil (as represented by the oil inclusions) to gas condensate was most likely caused by gas displacement.

MAPPING HYDROCARBON CHARGE HISTORIES: DETAILED CHARACTERISATION OF THE SOUTH PEPPER OIL FIELD, CARNARVON BASIN

The South Pepper Field is a small hydrocarbon accumulation located in the Barrow Sub-basin, North West Shelf. In this study, an integrated approach has been adopted which uses new analytical approaches, and combines fluid inclusion, micro and conventional GC-MS, stable isotope, mineralogical and petrological data, to allow the accurate reconstruction of the charge history of this field. The micro GC-MS work on oil-bearing fluid inclusions in the reservoir section allows, for the first time, a comparison to be made between the geochemical characteristics of the presently reservoired oil with samples of the palaeo-r eservoired oils, as preserved within the fluid inclusions.Oil inclusion abundances (OIA) recorded within the reservoir section in South Pepper-1 show two distinct abundance peaks, which are interpreted to correspond to zones of high oil saturation. The first occurs near the top of the reservoir, in sands that are presently gas saturated and represents a palaeo-oil column. The oil inclusions occur primarily within pre-existing ankerite cement that crystallised from highly saline fluids, probably derived from Palaeozoic evaporites. Carbon isotope compositions measured on the ankerite are isotopically depleted, consistent with the derivation of CO2 from the maturation of organic matter. Geochemical characterisation of the oil contained within these inclusions shows the presence of biomarkers such as 30-norhopanes and methylhopanes which are indicative of a calcareous source rock. This excludes the Jurassic Dingo Claystone as a source for this early oil charge and migration of oil from a pre-Jurassic source rock is inferred. Subsequent uplift and sub-aerial exposure of the basin margin during the Middle Miocene allowed fresh waters to dilute formation waters in the Barrow Group and biodegrade this early oil charge. However, the abundance of highly water-soluble compounds in the fluid inclusion oil suggests that biodegradation occurred subsequent to initial oil emplacement.The second oil inclusion abundance peak corresponds to the present-day oil zone and, although absolute oil inclusion abundances are similar to those recorded in the upper zone, the fluorescence colours are significantly different, suggesting a different source for the second oil charge. Geochemical characterisation of oil recovered by DST confirms this later oil charge was derived from a more clay-rich oxic source and has previously been typed to the Upper Dingo Claystone. The low abundance of this type of oil inclusion in samples from above the present GOC indicates that this later oil charge failed to accumulate at the top of the reservoir and so it cannot have been displaced by a later gas charge. Rather, the oil inclusion data suggest the emplacement of gas, probably derived from Triassic source rocks, occurred either prior to, or coincident with, the second oil charge.High OIA in the presently water bearing reservoir of South Pepper-3 suggests that high oil saturation originally extended beyond the present OWC. However, the absence of stratigraphically equivalent high OIA samples in wells from the east of the field suggests that late stage westerly tilting of the structure resulted in a reduction in closure and loss of oil across the eastern spill point. The presence of high gas readings and associated amplitude anomalies in the Windalia Radiolarite suggests that hydrocarbons are continuing to leak up the bounding fault. However, the absence of significant residual oil zones in other wells suggests that liquids were largely retained and that leakage involved the progressive bleeding of gas across a soft seal.