Reservoir Seal Research Articles

Petroleum System of the Sufyan Depression at the Eastern Margin of a Huge Strike‐slip Fault Zone in Central Africa

Abstract:The present paper mainly studies the petroleum system of the Sufyan Depression in the Muglad Basin of central Africa and analyzes its control of hydrocarbon accumulation. On the basis of comprehensive analysis of effective source rock, reservoir bed types and source–reservoir–seal assemblages, petroleum system theory has been used to classify the petroleum system of the Sufyan Depression. Vertically, the Sufyan Depression consists of two subsystems. One is an Abu Gabra subsystem as a self generating, accumulating and sealing assemblage. The other subsystem is composed of an Abu Gabra source rock, Bentiu channel sandstone reservoir and Darfur group shale seal, which is a prolific assemblage in this area. Laterally, the Sufyan Depression is divided into eastern and western parts with separate hydrocarbon generation centers more than 10 000 m deep. The potential of the petroleum system is tremendous. Recently, there has been a great breakthrough in exploration. The Sufyan C‐1 well drilled in the central structural belt obtained high‐yielding oil flow exceeding 100 tons per day and controlled geologic reserves of tens of millions of tons. The total resource potential of the Sufyan Depression is considerable. The central structural belt is most favorable as an exploration and development prospect.

Facies analysis of a large-scale Jurassic shelf-lagoon: the Kamar-e-Mehdi Formation of east-central Iran

The Callovian–Lower Kimmeridgian Kamar-e-Mehdi Formation of the Tabas Block (east-central Iran) is an up to 1,350-m-thick, fine-grained, marly-calcareous unit containing a basal Echellon Limestone Member (up to 180 m thick) and a terminal Nar Limestone Member (up to 100 m thick). The formation was deposited in a relatively deep shelf-lagoon that was part of the large-scale carbonate system of the Esfandiar Subgroup, extending N–S for about 500 km along the strike with a width of up to 100 km. The lagoonal Kamar-e-Mehdi Formation shows sedimentation rates of 150 m/myr, twice as high as those of the shelf-edge carbonate barrier (Esfandiar Platform). The repetitive lithologies and uniform depositional environment suggest equilibrium conditions between sedimentation and subsidence, related to constant slow rotation of the Tabas fault-block around a horizontal axis, the platform sitting on the crest, and the lagoon occupying the dip-slope. Lagoonal sedimentation was dominated by suspended carbonate mud and peloids from the eastern Esfandiar Platform whereas the subordinate siliciclastic material was derived from the west (Yazd Block). The diverse macrobenthos (mainly bivalves) suggests fully marine conditions for the major part of the Kamar-e-Mehdi Formation. However, towards the upper part, biotic impoverishment and the deposition of skeletal-poor, evaporitic sediments indicate increasing restriction. The overlying Magu Gypsum Formation marks the end of an arid basin-fill cycle and possibly forms an effective seal for hydrocarbon reservoirs in that area. The Esfandiar Subgroup was a Neotethys-facing carbonate margin, forming part of a belt of carbonate systems tracking the margins of the Iran Plate during Callovian to Late Jurassic times.

Introduction to this special section—Shale geophysics

Shales comprise a large proportion of most sedimentary basins and form the seal and source rocks for many hydrocarbon reservoirs. They also have a major impact in gas plays involving shale where they act as both the source rock and reservoir. Because of their low permeability, there is great interest in using shales as host rocks for waste storage. In the petroleum industry, shales cause billions of dollars in losses annually through, for example, pore-pressure-related kicks, blow-outs, and wellbore instability. Shales have a decisive impact on fluid-flow and seismic-wave propagation because of their low permeability and anisotropic microstructure.

Citronelle Dome: A giant opportunity for multizone carbon storage and enhanced oil recovery in the Mississippi Interior Salt Basin of Alabama

The Citronelle Dome is a giant, salt-cored anticline in the eastern Mississippi Interior Salt Basin of southern Alabama that is located near several large-scale, stationary, carbon-emitting sources in the greater Mobile area. The dome forms an elliptical, four-way structural closure containing opportunities for CO2-enhanced oil recovery (CO2-EOR) and large-capacity saline reservoir CO2 sequestration. The Citronelle oil field, located on the crest of the dome, has produced more than 169 million bbl of 42–46 API gravity oil from sandstone bodies in the Lower Cretaceous Rodessa Formation. The top seal for the oil accumulation is a thick succession of shale and anhydrite, and the reservoir is underfilled such that oil-water contacts are typically elevated 30–60 m (100–200 ft) above the structural spill point. Approximately 31–34% of the original oil in place has been recovered by primary and secondary methods, and CO2-EOR has the potential to increase reserves by up to 20%. Structural contour maps of the dome demonstrate that the area of structural closure increases upward in section. Sandstone units providing prospective carbon sinks include the Massive and Pilot sands of the lower Tuscaloosa Group, as well as several sandstone units in the upper Tuscaloosa Group and the Eutaw Formation. Many of these sandstone units are characterized by high porosity and permeability with low heterogeneity. The Tuscaloosa-Eutaw interval is capped by up to 610 m (2000 ft) of chalk and marine shale that are proven reservoir seals in nearby oil fields. Therefore, the Citronelle Dome can be considered a major geologic sink where CO2 can be safely stored while realizing the economic benefits associated with CO2-EOR.

Geological features and evaluation techniques of deep-seated volcanics gas reservoirs, Songliao Basin

Abstract The significant breakthrough of natural gas exploration in deep-seated volcanic rocks of Songliao Basin, China, demonstrates that the volcanic rocks as reservoirs can form natural gas accumulations where excellent source–reservoir–caprock assemblages exist. This paper reveals several features of volcanic gas accumulations: (1) Two types of gas reservoirs, including hydrocarbons and non-hydrocarbons, are developed; the former is organic and usually trapped in shallower volcanics associated with sub-deep-seated faults, while the latter is mainly inorganic and accumulated in deep-seated volcanics associated with large-scale deep-cut basement faults. (2) Lower Cretaceous Shahezi Formation coal series source rocks, Yingcheng Formation volcanics, and Denglouku Formation mudstone form good source–reservoir–seal associations that control the major volcanic plays. (3) Volcanic crater and eruptive facies spread along deep-seated faults, so discordogenic faults control the distribution of large-scale volcanic gas reservoirs. (4) Fracture zones, accompanied with large-scale faults, control the distribution of high-yield zones. (5) Effusive volcanic rocks in the deep parts of sags have huge thickness and touch extensively with source rocks, so the gas accumulation potential is promising if reservoirs exist. Evaluation techniques can be summarized in three steps: (1) Determining the distribution of volcanic rocks by joint inversion of gravitational, magnetic, and seismic data. (2) Predicting the distribution of volcanic reservoirs by multiple methodologies. (3) Predicting the distribution of gas-bearing volcanic rocks by integrated methods, including gas detention.

Changxing Formation biohermal gas pools and natural gas exploration, Sichuan Basin, China

Abstract Plain fluvial facies, paralic facies, shallow gentle slope facies on carbonate platforms, platform marginal reef facies, Kailiang trench facies, and north Sichuan western Hubei ocean basin facies are developed in the Permian Changxing Formation and have favorable source–reservoir–seal conditions. To improve the seismic prediction reliability of biohermal anomalies, a recognition mode of biohermal seismic anomalies was established in the late 1990s based on the geological features of known reefs and the corresponding seismic reflection features, and 182 biohermal anomalies were found in eastern Sichuan. Researches on sedimentary facies reveal a platform marginal reef facies from both sides of Kailiang trench to western Hubei, and the seismic anomalies of 36 marginal reefs have been found there. These marginal reefs have large areas and high drill reserves. The facies belt extends to the western margin of the basin. Many point reefs are developed on the slope platform facies, and 146 seismic anomalies of point reefs are found in eastern basin. Point reefs are developed widely in central basin.

From pore-pressure prediction to reservoir characterization: A combined geomechanics-seismic inversion workflow using trend-kriging techniques in a deepwater basin

To optimize drilling decisions and well planning in overpressured areas, it is essential to carry out pore-pressure predictions before drilling. Knowledge of pore pressure implies knowledge of the effective stress, which is a key input for several geomechanics applications, such as fault slip and fault seal analysis and reservoir compaction studies. It is also a required input for 3D and 4D seismic reservoir characterization. Because the seismic response of shales and sand depends on their compaction history, the effective stress will govern the sedimentary seismic response. This is in contrast to normally pressured regimes, where the depth below mudline (or overburden stress) is typically used to characterize the compaction effect.

CO2/water interfacial tensions under pressure and temperature conditions of CO2 geological storage

Abstract CO2 storage in aquifers and depleted hydrocarbon reservoirs is one of the most promising options for reducing CO2 atmospheric concentration. However, its implementation in a given reservoir requires demonstration that CO2 leakage through the reservoir seal (caprock) is extremely limited. One possible cause of rapid leakage is capillary failure of the caprock, which is to a large extent controlled by the CO2/water interfacial tension (IFT). This paper presents pendant drop measurements of IFTs between water and CO2 in a range of temperatures (308–383 K) and pressures (5–45 MPa) relevant to CO2 storage in deep geological formations. Phase densities were measured simultaneously, allowing precise IFT determinations. Increasing the pressure along a given isotherm, IFTs were observed to decrease sharply, then to level off and reach, for pressures above 20 MPa, a pseudo-plateau that decreases slightly with temperature, from around 30 mN/m at 308 K to 23 mN/m at 383 K. The presence of salt (20 g/l NaCl) in the water phase has a negligible effect on the IFT. An important conclusion for CO2 storage is that CO2/brine IFTs have low but reasonable values (higher than 20 mN/m) even at the highest pressures and temperatures examined, and that, neglecting all other possible effects, CO2 storage can, therefore, be considered even in deep geological formations.

Gas breakthrough pressure for hydrocarbon reservoir seal rocks: implications for the security of long‐term CO2 storage in the Weyburn field

AbstractThis paper reports a laboratory study of the gas breakthrough pressure for different gas/liquid systems in the Mississippian‐age Midale Evaporite. This low‐permeability rock formation is the seal rock for the Weyburn Field in southeastern Saskatchewan, Canada, where CO2 is being injected into an oil reservoir for enhanced recovery and CO2 storage. A technique for experimentally determining CO2 breakthrough pressure at reservoir conditions is presented. Breakthrough pressures for N2, CO2 and CH4 were measured with the selected seal‐rock samples. The maximum breakthrough pressure is over 30 MPa for N2 and approximately 21 MPa for CO2. The experimental results demonstrate that the Weyburn Midale Evaporite seal rock is of high sealing quality. Therefore, the Weyburn reservoir and Midale Beds can be used as a CO2 storage site after abandonment. The measured results also show that the breakthrough pressure of a seal rock for a gas is nearly proportional to the interfacial tension of the gas/brine system. The breakthrough pressure of a CO2/brine system is significantly reduced compared with that of a CH4/brine system because of the much lower interfacial tension of the former. This implies that a seal rock that seals the original gas in a gas reservoir or an oil reservoir with a gas cap may not be tight enough to seal the injected CO2 if the pressure during or after CO2 injection is the same or higher than the original reservoir pressure. Therefore, reevaluation of the breakthrough pressure of seal rocks for a given reservoir is necessary and of highest priority once it is chosen as a CO2 storage site.

Use of interferometric techniques for detecting subsidence in the oil fields of Kuwait using Synthetic Aperture Radar Data

Subsidence in Burgan oil field of Kuwait has been studied by Interferometric technique using Synthetic Aperture Radar data. Repeat pass Interferometry is applied to the study area that accounts for infinitesimal changes in the topographic elevations. Subsidence of about 27 mm over a period of 3 years was estimated in Burgan oil field area. The study is significant since continued subsidence may result in reduction of porosity of host formation and may activate the sub-surface geological structures, which can compromise the integrity of the reservoir seal, leading to migration of hydrocarbons to other formations and areas.

Petroleum systems in the eastern and central Taurus region, Turkey

The Autochthonous Taurus ‘known’ petroleum system is geographically located in the eastern Taurus region and includes the Allochthonous Units and Miocene–Pliocene sequences in the Adana Basin. The total thickness of the Early Palaeozoic to Cenozoic sediments reaches 9500–10400 m. The eastern Taurus region is a major petroleum source area with three source rocks: Upper Devonian limestones, Lower Carboniferous shales and dark carbonates, and Upper Permian algal limestones and shales. The Burdigalian–Serravillian sandstones and limestones and the Late Tortonian–Messinian evaporites and shales of the Adana Basin constitute the reservoir–seal rock combinations in this petroleum system. The main periods for oil generation from these source rocks occurred during the Aptian to Bartonian, Maastrichtian and Lutetian to the present. However, the main periods for oil generation for the effective source rocks (Lower Carboniferous and Upper Permian formations) began 40 mybp and continued to 20 mybp. Oil and gas traps in this petroleum system are formed by thrusting due to Late Cretaceous and Late Eocene tectonism, strike–slip faults and unconformity surfaces.

Stratigraphic system analysis and business decision-making

The revolution in the stratigraphic sciences has impacted all aspects of petroleum exploration and development. It is now possible to reconstruct depositional history on a scale of tens to a few hundreds of thousands of years. Depositional systems and sequences can be recognized from seismic reflection patterns, log patterns, and biologic evolutionary sequences. The Recent is now truly the basis for understanding paleogeography, depositional patterns, reservoir geometries, and attributes. Not only is it possible to predict patterns of physical sedimentary attributes, but the relationship of structural and depositional histories can now be modeled. The interrelationship of basinal history, subsidence, depositional sequences, and onlap and offlap patterns can be understood and predicted. The history of rising and falling sea levels has been defined on scales ranging from millions to a few hundred thousand years. High-stand, flooding surfaces, and low-stand depositional sequences can be defined from petrophysical, seismic, and depositional patterns. The multivariant analysis of stratigraphic attributes and their patterns can be the basis for predicting the presence and distribution of unconformities, reservoir intervals and their potential productivity, and permeability and porosity distributions. From the analysis of stratigraphic sequences, it is possible to predict reservoir seals, distribution of overpressured intervals and zones, and avenues of petroleum migration. Without the reconstruction of the regional stratigraphic framework, it is impossible to interpret seismic, petrophysical, and depositional patterns. Stratigraphic analysis requires that time-rock correlations be developed prior to determining the structural history. Prediction of the time and place for the entrapment of hydrocarbons requires the knowledge of fluid-flow “plumbing” patterns, the presence of source rocks, the location of overpressured intervals, and identification of hydrocarbon seals. Facies mapping is required to determine the nature and distribution of reservoir units. Stratigraphic analysis includes time-rock correlation based upon paleontology, patterns of seismic reflections, basinal history, and stratigraphic paleogeographic …

Discovery and analysis of ultra-micro grinding grain texture in slipping lamellae of ductile-brittle zone

Based on the observation of the deep bore cores sampled from the State of Cali-fornia, USA, preferred arranged particulate concentration belts were found in the ultra-slipping lamellae. And the same phenomenon was found again later in the bore cores from the petroleum basin in the Northern Shaanxi Province. It may be the product of the dynamic processes involv-ing tumbling, grinding and compresso-shearing functions, so the spherical particulates with ul-tra-size of nm and mm are called grinding grain. The formation of the grinding grains is related with the ductile-brittle deformation, the lateral pressure of the slipping, and the very low grade of dynamic metamorphism of the rocks. Based on the systematic analysis, it is indicated that some elements like Nb and Ta are enriched in the grinding grains in the granitic rocks because of the chemical differentiation, and that the slipping lamellae bearing grinding grains in mudstone with smear efficiency prove a perfect seal for oil and gas reservoirs. Meanwhile, the paper provides bases for the studies on the fast stick-slip movement and shear paradigm.

FAULT AND TOP SEAL INTEGRITY AT RELAYS AND INTERSECTIONS USING A 3D DISTINCT ELEMENT CODE

It has long been known that faults and horizon boundaries can greatly affect the magnitude and orientation of the in-situ rock stress state. Significant success has been shown in the geo-engineering disciplines, whereby geomechanical models have been built to model local stress fields generated by rock mass inhomogeneities.In this work 3DEC (3D) the discrete element code has been applied to model stress perturbations around three simple fault configurations, two relay configurations (relay ramp and horst structure) and one fault intersection. The results show rotation in the principal stress orientation and stress magnitudes of the regional stress field about the faults. The degree of rotation of the principal stress direction and the stress magnitude are dependant on the fault friction angle parameter, the angle of maximum principal stress to the fault plane and the ratio of maximum to minimum principal stress. The degree of perturbation is demonstrated graphically in the surrounding rock mass along the fault strike, the perturbation generated by the fault can be up to 1.4 times the magnitude of the maximum principal regional stress and is highly dependent on friction angle.Case studies are presented where this 3D numerical technique has been used to truly integrate risking methods on the fault plane and in the surrounding rock mass. Case study examples are given for the Otway Basin, South Australia and the Bonaparte Basin, Timor Sea, where these predictors can be applied to accurately identify high-risk reservoir seals.

Genesis and distribution of natural gas in the foreland basins of China

This article discusses the geochemical characteristics of various types of natural gas and features of gas reservoirs in the foreland basins in China. We conclude that there are four types of natural gas in origin: coal-formed cracking gas, coal-formed thermal gas, oil-type thermal gas and mixed gas. Coal-formed gases are generated from three sets of coal measures: Permo-Carboniferous Formations in the Ordos Basin, Upper Triassic Formations in the Qaidam Basin, and Triassic Formations in northwest China. Source rocks for the oil-type gas include Permian Formations in the Junggar Basin, Triassic Formations in the Qaidam Basin, and lacustrine source rocks in basins along the Hexi Corridor. Abnormally high pressures commonly exist in the gas reservoirs in foreland basins where multiple sets of source–reservoir–seal combinations are present, and the major trap type is the anticlinal trap type and faults are the major hydrocarbon migration pathways.

The Fulmar Field, Blocks 30/16, 30/11b, UK North Sea

Abstract The Fulmar Field is located on the southwestern margin of the Central Graben in Blocks 30/16 and 30/11b of the UK sector of the North Sea. The Fulmar Field was discovered 1975 and began producing in 1982. Currently (2000) the field produces at a rate of 8000 BOPD at a watercut above 90% mainly through the process of rinsing of residual oil. Total STOIIP is 822 MMBBL and ultimate recovery is 567 MMBBL of oil and 342 BSCF of wet gas. As of the end of 1999, 547 MMSTB of oil and 325 BSCF of wet gas had been produced. The high recovery factor (69%) of the field is thought to be linked to the combination of well density, large length of reservoir perforated, excellent reservoir quality, sweep by water injection, good pressure support and oil stripping from a secondary gas cap formed early in field life. The Fulmar Field is a small triangular, partly eroded domal anticline with steeply dipping flanks, located on a fault terrace within the western margin of the South West Central Graben at a depth between 9900 and 11 500 ft TVDss. The field has been shaped by three major tectonic processes: (1) halokinesis, (2) syndepositional reactivation of Caledonian basement faults; and (3) syndepositional through post-depositional displacements along the nearby Auk Horst Boundary Fault. The reservoir consists of thick Upper Jurassic, shallow marine, very bioturbated sandstones of the Fulmar Formation overlain by the deeper marine Ribble Sands interbedded within the Kimmeridge Clay Formation. Reservoir seal is provided by the Kimmeridge Clay in the west and Upper Cretaceous chalks which unconformably overlie the Fulmar Formation in the east. The reservoir section has been lithostratigraphically subdivided into six reservoir units and 24 sub-units. Integration of bio- and lithostratigraphic data has led to a sequence stratigraphic model of the Jurassic succession in the Fulmar Field. In total four depositional sequences are identified, which progressively onlap Triassic basement towards the southwest. The older Jurassic sequences are characterized by rapid progradation of shoreface sands, whereas aggradation of thick sediment packages is typical of the younger intervals. This change of depositional architecture is linked to syndepositional reactivation of basement faults. Major transgressive intervals form intra-reservoir barriers or baffles to flow. Facies changes (Mersey-Clyde Sands) from proximal to distal facies are abrupt and are also linked to basement faults.

Detecting high overpressure

Normal pressure is pore fluid pressure that equals the hydrostatic pressure of a column of formation water extending to the surface. Overpressure is pore fluid pressure greater than normal pressure. However, no standard definition exists for what constitutes high overpressure. What can be said is that high overpressure often means trouble. For an explorationist, it could mean blown reservoir seals; for a driller, it could mean excessive time spent fighting formation fluid influxes and/or drilling fluid losses. A practical upper limit for pore pressure is the overburden stress. Pore pressures in this range are on the verge of opening fractures that can vent fluid and bleed off pressure like a pressure relief valve. Therefore, criteria for defining high overpressure are sometimes expressed in terms of a percentage of the overburden stress, say, pore pressure greater than 90% of the overburden stress. In this article, high overpressure will be defined simply as pore pressure that approaches the overburden stress. All but one potential cause of overpressure can produce high pressure. Fortunately, the mechanism that cannot generate high pressure is the most common cause of overpressure. Therefore, detecting high overpressure basically boils down to determining where extraordinary overpressure mechanisms may be encountered. Overpressure detection is based on the premise that pore pressure affects compaction-dependent geophysical properties such as density, resistivity, and sonic velocity. Shales are the preferred lithology for pore pressure interpretation because they are more responsive to overpressure than most rock types. Consequently, overpressure detection centers around shale deformation behavior. For stress ranges of practical interest, shale compaction is controlled by the difference between total applied stress and pore fluid pressure. This difference, termed the effective stress , represents the portion of the total stress carried by the rock grains. Figure 1 illustrates the effective stress concept with laboratory data for …

ABSTRACT: Diagenetic Controls on Reservoir Quality and Seal Integrity: Deep Jurassic Targets, Norwegian Sea

ABSTRACT: Diagenetic Controls on Reservoir Quality and Seal Integrity: Deep Jurassic Targets, Norwegian Sea

ABSTRACT: Early Marine Cementation at Parasequence and Sequence Boundaries: Implications for Seal Development and Reservoir Compartmentalization

ABSTRACT: Early Marine Cementation at Parasequence and Sequence Boundaries: Implications for Seal Development and Reservoir Compartmentalization

NEW PETROLEUM MODELS IN THE PEDIRKA BASIN, NORTHERN TERRITORY, AUSTRALIA

The northern Pedirka Basin in the Northern Territory is sparsely explored compared with its southern counterpart in South Australia. Only seven wells and 2,500 km of seismic data occur over a prospective area of 73,000 km2 which comprises three stacked sedimentary basins of Palaeozoic to Mesozoic age. In this area three petroleum systems have potential related to important source intervals in the Early Jurassic Eromanga Basin (Poolowanna Formation), the Triassic Simpson Basin (Peera Peera Formation) and Early Permian Pedirka Basin (Purni Formation). They are variably developed in three prospective depocentres, the Eringa Trough, the Madigan Trough and the northern Poolowanna Trough. Basin modelling using modern techniques indicate oil and gas expulsion responded to increasing early Late Cretaceous temperatures in part due to sediment loading (Winton Formation). Using a composite kinetic model, oil and gas expulsion from coal rich source rocks were largely coincident at this time, when source rocks entered the wet gas maturation window.The Purni Formation coals provide the richest source rocks and equate to the lower Patchawarra Formation in the Cooper Basin. Widespread well intersections indicate that glacial outwash sandstones at the base of the Purni Formation, herein referred to as the Tirrawarra Sandstone equivalent, have regional extent and are an important exploration target as well as providing a direct correlation with the prolific Patchawarra/Tirrawarra petroleum system found in the Cooper Basin.An integrated investigation into the hydrocarbon charge and migration history of Colson–1 was carried out using CSIRO Petroleum’s OMI (Oil Migration Intervals), QGF (Quantitative Grain Fluorescence) and GOI (Grains with Oil Inclusions) technologies. In the Early Jurassic Poolowanna Formation between 1984 and 2054 mRT, elevated QGF intensities, evidence of oil inclusions and abundant fluorescing material trapped in quartz grains and low displacement pressure measurements collectively indicate the presence of palaeo-oil and gas accumulation over this 70 m interval. This is consistent with the current oil show indications such as staining, cut fluorescence, mud gas and surface solvent extraction within this reservoir interval. Multiple hydrocarbon migration pathways are also indicated in sandstones of the lower Algebuckina Sandstone, basal Poolowanna Formation and Tirrawarra Sandstone equivalent. This is a significant upgrade in hydrocarbon prospectivity, given previous perceptions of relatively poor quality and largely immature source rocks in the Basin.Conventional structural targets are numerous, but the timing of hydrocarbon expulsion dictates that those with an older drape and compaction component will be more prospective than those dominated by Tertiary reactivation which may have resulted in remigration or leakage. Preference should also apply to those structures adjacent to generative source kitchens on relatively short migration pathways. Early formed stratigraphic traps at the level of the Tirrawarra Sandstone equivalent and Poolowanna Formation are also attractive targets. Cyclic sedimentation in the Poolowanna Formation results in two upward fining cycles which compartmentalise the sequence into two reservoir–seal configurations. Basal fluvial sandstone reservoirs grade upwards into topset shale/coal lithologies which form effective semi-regional seals. Onlap of the basal cycle onto the Late Triassic unconformity offers opportunities for stratigraphic entrapment.