Hydrocarbon Entrapment Research Articles

English

Gravity data were acquired along two profiles in some parts of the Njaba River sub-basin. Profile A-A’ and B-B’ run for about 30 and 12 km respectively with the end of the two profiles meeting at Oguta Lake. The Bouguer gravity anomaly along Profile A-A’ revealed initial positive gravity values to a wavelength of about 21 km and then followed by a sudden drop of the observed gravity showing a significant gravity minimum. Profile B-B’ showed an alternating gravity high and low which was followed by a sudden extremely low value in the observed gravity. Further investigation showed that the structure modeled is graben and horsts bounded by two normal faults. The high gravity observed is due to the lesser density contrasts between the sediments and the basement which had resulted from the up-warping of the crust. The area showing low gravity revealed thick sedimentary accumulation of recently deposited alluvium deposits deposited in the subsided area bounded by these two faults. The structural framework of the parts of the sub-basin studied suggested an environment favorable for large scale entrapment of hydrocarbons. This is justified by the ongoing exploration and exploitation of petroleum resources in the study area. Key words: Gravity profiles, gravity anomaly, density contrasts, sub-basin, graben and horst, Oguta Lake.

High-quality data from the Eendracht MC3D seismic survey gives insight about the hydrocarbon potential of the Carnarvon Basin

The Eendracht 3D multi-client seismic survey covers an area of about 8,000 km2. It is located in the Carnarvon Basin, one of Australia’s most hydrocarbons-prolific basins. The basin is filled with thick Paleozoic, Mesozoic, and Cenozoic sedimentary successions, deposited during multiple phases of extension and following the breakup of Gondwana. The most prominent structural trend is northeast—southwest with basins and sub-basins aligned as a consequence of the rifting event, which occurred during Jurassic to Early Cretaceous. Recent discoveries like Ragnar–1 and Tallaganda–1 show a working petroleum system and the high prospectivity of the Carnarvon Basin. The Eendracht survey covers a relatively less-explored but prolific area of the basin and provides a large volume of high-quality 3D seismic data. New technologies for acquisition and processing such as Fresnel Zone Bining, Interactive Azimuthal Anisotropy Analysis, and Diffracted Noise/Multiple Attenuation have been used. The hydrocarbon generation, migration, and entrapment in the Carnarvon Basin is controlled by Jurassic to Early Cretaceous syn- and post-rift structures, deposition, and Neogene reactivation. The most dominant successions in the Basin are Triassic to Lower Cretaceous sedimentary units. The Triassic Mungaroo Formation is the main reservoir found in the area covered by the Eendracht survey. Northeast–southwest-oriented extensional structures create potential traps for hydrocarbons and structures like horsts, tilted fault blocks, drapes, and fault-over anticlines can now be better visualised and analysed due to the 3D character of the Eendracht survey.

Geology and hydrocarbon potential of Neoproterozoic–Cambrian Basins in Asia: an introduction

In 2005, the Maghreb Petroleum Research Group (MPRG), University College London, initiated a major research programme focused on the relatively poorly understood Neoproterozoic petroleum systems of the world. A series of research projects were undertaken to understand the generation and entrapment of hydrocarbons in this unique geological time interval, which is dominated by several episodes of global glaciations and post-glacial transgressions, coupled with basin development and rifting on a more local scale (Craig et al. 2009). The research started with a field-based study of the Neoproterozoic sequences in North Africa (Libya, Morocco and Mauritania) and northern India (Rajasthan and Jammu & Kashmir). A series of international conferences, with field excursions/workshops, were run in parallel with the research programmes. The first of these was held at the Geological Society of London in November 2006 and the proceedings were published in 2009 in Geological Society London, Special Publication 326, entitled, ‘Global Neoproterozoic Petroleum Systems: the emerging potential in North Africa’ (Craig et al. 2009). The second international conference was held at the University of Jammu in 2008 with a focus on the Neoproterozoic petroleum systems of Asia, including India, Pakistan, Oman, China and Siberia (Bhat et al. 2008) (Fig. 1). This current volume contains some of the papers presented at the Jammu conference, in addition to new research on the geology and hydrocarbon potential of the Neoproterozoic–Cambrian basins of Asia. A third and concluding conference and an associated third Geological Society Special Publication will focus on the Neoproterozoic petroleum systems in regions of the world not covered in the previous volumes (mainly North and South America, western and southern Africa and Australia) and will complete the project to provide a global synthesis of the Neoproterozoic petroleum systems. The present volume contains fifteen papers covering the Neoproterozoic petroleum systems of India (Ojha, Ram, Kumar and Majid et al.), Pakistan and (Jamil & Sheikh and Siddiqui), Oman (Cozzi et al.), China (Turner) and Siberia (Howard et al.). The remaining five papers concentrate on various aspects of Neoproterozoic geology and palaeobiology, including stratigraphy (Tewari) and tectonics (Mishra & Mukhopadhyay) of the NW Himalaya, salt tectonics in Oman (Smith), acritarchs in Oman (Butterfield & Grotzinger) and the palaeobiology of the Vindhyan succession in central India (Sharma & Shukla). This Introduction provides a synthesis of the key conclusions in a palaeogeographic context, but for details the reader is referred to the relevant articles in this volume.

FAULT SLICING IN THE INTERPRETATION OF FAULTS IN SEISMIC DATA PROCESSING IN ATALA PROSPECT OF RIVER STATE, NIGERIA

Faults are of high interest in petroleum development and production because they segment a reservoir. As a result of the role faults play in the entrapment of hydrocarbons, the techniques for finding and mapping them have considerable practical importance. A fault slice is a section sliced from a 3 – D data volume parallel to the interpreted position of a fault plane and can be used in several ways for the study of faults. The tracking of horizons on fault slices provides a map of fault thrown. Since a fault slice is found within one fault block, it becomes necessary in the study of growth in that block. There exist splinter faults that cause a lot of difficulty in horizon tracking because the data under study experiences small throw faults of limited laterial extent spawned by the major growth faults or parent fault. These splinter faults are secondary faults caused by movement on parent fault. A lot of Splinter faults were identified in the area of study and the azimuths of the Splinter faults relative to the parent fault are fairly constant.

Inferring Hydrocarbon Migration and Sealing Potentials of Some Shales of the Anambra Basin (South-Eastern Nigeria) from Their Paragenesis and Geotechnical Index Properties

Shale samples from designated units of the Imo, Nsukka, Mamu, Enugu and Nkporo Formations of the Anambra Basin were subjected to X-ray diffraction and geotechnical index tests to determine the potential of the Formations to either create hydrocarbon migration pathways or to form seals for hydrocarbon entrapment. The X-ray diffraction results indicate that the shales are made up of silicate minerals with carbonates and sulphates. Results of the geotechnical index tests showed that the plasticity index (PI) for the Enugu shale ranges from 16 to 24 (average of 20) while the toughness index (TI) ranges from 0.4 to 0.8 (average of 0.7). The PI for the shales of Imo and Nsukka Formations ranges from 62 to 72 and 34–59 with averages of 67 and 46 respectively while their TIs range from 0.8 to 1.7 and 1.5–2.2 with averages of 1.3 and 1.9, respectively. These properties dispose the Enugu shale to easy amenability to loss of cohesion, deforming in a brittle manner, when subjected to shearing stress with the ability to create joints and faults that are pathways of hydrocarbon migration. Conversely, the properties of the shales of the Imo and Nsukka Formations give them the capacity to absorb high shearing stress without loss of cohesion thereby deforming in a ductile manner, which prevents the leakage of fluids in fluid migration. Hence, Enugu shale has the highest potential of creating hydrocarbon pathways while the shales of the Imo and Nsukka Formations are better seal rocks than others.

Integration of Well Logs and Seismic Data for Prospects Evaluation of an X Field, Onshore Niger Delta, Nigeria

Hydrocarbon reservoir beds have been delineated using direct hydrocarbon indicator on seismic sections as well as well logs data in X field, Onshore Niger Delta. The research methodology involved horizon interpretation to produce sub-surface structure map. Geophysical well log signatures were employed in identifying hydrocarbon bearing sand. The well-to-seismic tie revealed that the reservoir tied directly with hydrocarbon indicator (bright spot) on the seismic sections. The major structure responsible for the hydrocarbon entrapment is anticline. The crest of the anticline from the depth structural map occurs at 3450 metres.

Albian–Cenomanian–Turonian carbonate-siliciclastic systems of the Arabian Plate: advances in diagenesis, structure and reservoir modelling: introduction

This special issue contains a thematic set of papers arising from a conference entitled ‘Second Arabian Plate Geology Workshop: Albian–Cenomanian–Turonian Carbonate-Siliciclastic systems of the Arabian Plate’, organized by the EAGE in Abu Dhabi in January 2010. Full conference abstracts are published in GeoArabia (2010, Vol. 15, No. 1). The meeting followed a very successful First Arabian Plate Geology Workshop in Oman in 2008, which focused upon Barremian to Aptian systems (van Buchem et al . 2010). A key recommendation from that meeting was that subsequent workshops should be broadened to consider the impact of stratigraphy on patterns of diagenesis and, ultimately, on reservoir performance. Consequently, the Albian–Cenomanian–Turonian Workshop concentrated not just on unification of stratigraphic nomenclature, but also on the relationship between sedimentation, structural style, diagenesis and their impact on hydrocarbon entrapment and production. The Albian–Cenomanian–Turonian interval is one of the most important petroleum systems on the Arabian Plate. Large volumes of hydrocarbon are hosted within clastic (mostly Albian) and carbonate (largely Cenomanian–Turonian) reservoirs in Oman, United Arab Emirates (UAE), Qatar, Kuwait, Iran and Iraq. The fine-grained siliciclastic sediments of the early Albian form regional seals to the underlying Aptian reservoirs, whilst the organic-rich mudstones deposited in Albian and Cenomanian intrashelf basins (e.g. Natih B Formation, Oman; Kazhdumi Formation, Iran) are important hydrocarbon source rocks. Compressional tectonism, initiated in the latest Cenomanian to early Turonian with the partial closure of Neotethys, and completed in the early Tertiary, was responsible for the formation of the main hydrocarbon traps in the region and for triggering hydrocarbon maturation and migration. Margin-proximal areas (i.e. Zagros Simply Folded belt in Iran and Iraq) are characterized by the development of short wavelength, often asymmetric anticlinal traps, whilst areas distal to the margin (i.e. Mesopotamian foreland basin of Iraq and Arabian Plate in Kuwait, Qatar, Saudi …

Hydrocarbon breaching of a regional aquitard: The Devonian Ireton Formation, Bashaw area, Alberta, Canada

This study is an investigation of aquitard characteristics and hydrocarbon entrapment in the Upper Devonian strata of the Bashaw area of Alberta, Canada. Oil and gas are trapped at two stratigraphic levels, the Leduc-aged Bashaw Reef Complex (D-3) and the Camrose Member–Nisku Formation (D-2), which are separated by a low-permeability aquitard of the Ireton Formation, a marl with variable carbonate content. The Ireton aquitard provides the principal control to cross-formational fluid flow in the area. Over much of the Bashaw Reef Complex, the Ireton aquitard ranges from approximately 25 m (82 ft) thick to less than 1 m (3.3 ft) over paleotopographic highs. Associated with thinning is a change in lithofacies and carbonate content from approximately 50% carbonate in the thicker, more basinal facies to more than 80% carbonate and shallower-water facies over the paleotopographic highs of the Leduc. Early replacement dolomitization, probably by density-driven reflux, generated intercrystal porosity on the order of 3 to 4% in the more carbonate-rich facies, which rendered these parts of the aquitard less effective to later hydrocarbon retention. Subsequent differential compaction of the underlying reef complex led to a raised rim morphology and, in places, to a thickness inversion of the Ireton aquitard, that is, a thicker Ireton aquitard draped over the Leduc raised rims. As a result, petroleum migration occurred primarily along the raised rims and was trapped within the present-day highs that are draped by more than 10 m (32.8 ft) of Ireton aquitard. Where the overlying Ireton aquitard drape is less than 10 m (32.8 ft) in thickness, breaching and remigration from Leduc traps into the overlying Nisku-Camrose traps may have occurred and/or can be suspected. Invariably, the Ireton aquitard was breached where its carbonate content exceeded approximately 80% and where it is less than 4 m (13.1 ft) thick. The critical controls to hydrocarbon breaching are pervasive dolomitization of the Ireton aquitard with high carbonate content, which enhanced porosity and permeability, and aquitard thickness. Many Nisku and Camrose pools are situated either directly above or updip from such breaches.

The function of faults in hydraulic hydrocarbon entrapment: Theoretical considerations and a field study from the Trans-Tisza region, Hungary

The main focus of this work is the investigation of the hydraulic function of faults, which is dependent upon the fluid-potential field, based mainly on theoretical considerations. The study displays the joint application of different research techniques, particularly hydrogeological methods for the western part of the Trans-Tisza region, Hungary, where thermal water and hydrocarbon accumulations are known. During the research, seismic, well-log, lithostratigraphic, and hydraulic data were analyzed to determine the hydrogeological framework and the fluid-potential field of the study area. As a result, the heterogeneity of a thick (1000 m [3281 ft]) and regionally extensive argillaceous aquitard unit was established, which is divided by structural elements and relatively thin (150–200 m [492–656 ft]) sandy aquifer units. Furthermore, two major strike-slip fault zones connecting the overpressured sub-Neogene basement with the uppermost aquifer unit and also intersecting each other were identified. Based on the complex investigation, we determined that the identified faults represent direction-dependent control over the fluid-flow systems of the study area. Both proved to act vertically as conduits but transversely as barriers; they enable pressure dissipation and intensive water upwelling from the sub-Neogene basement, resulting in a fluid-potential anomaly and, at the same time, in hydrocarbon entrapment. Consequently, during hydrocarbon exploration, it is not definitely necessary to search for low-permeability faults because high-permeability faults can also be acting as direction-dependent barriers for fluid flow. Moreover, the research also pointed out that hydrogeological methods are effective in hydrocarbon exploration during the evaluation of hydraulic function of faults.

Detailed gravity studies over Jabera — Damoh region of the Vindhyan basin (Central India) and crustal evolution

Vindhyan Basin of Central India situated just north of SONATA rift zone, forms one of the major geotectonic segment of the Indian subcontinent which is associated with complex thermo-tectonic history. Southern part of this basin is known to contain favorable conditions for hydrocarbon entrapment. Keeping this in view, a detailed gravity survey network comprising 40 gravity bases and 1500 data points in an area of about 110 × 100 km2 was planned in and around Jabera-Damoh region. Analysis of Bouguer and free air gravity anomaly maps, prepared using fractal based gridding method, indicates presence of two sedimentary basins (Jabera and Damoh) faulted on either sides beside ridge like features. However, well-known Jabera domal structure appeared to be a shallow feature only. Inversion of gravity data further reveals presence of 5 to 6 km thick Vindhyan sediments in the Jabera basin which are underlain by Mahakoshal/Bijawar group of rocks, resting directly over the lower crust, thereby indicating almost total absence of granitic crust from this region. It appears that due to an underlying thermal anomaly, the entire region may have been subjected to sustained uplift, deformation, erosion and consequent crustal extension during early to mid Proterozoics which brought high velocity mafic crust to such shallow levels.

A review of stratigraphic simulation techniques and their applications in sequence stratigraphy and basin analysis

Stratigraphic simulation is a modelling methodology that can be used for exploration purposes to understand the key factors (sea-level change, subsidence, sediment supply rate) that control the stratigraphic geometries and architecture of a basin. Its application offers many advantages to scientists and researchers, as it provides a useful platform for analyzing and unraveling the complexities of sequence stratigraphy and basin development. A stratigraphic simulator models the stratal patterns of basins in various tectonic settings, such as in passive margins, foreland basins, retroarc foreland basins, interarc basins, remnant ocean basins, growth-faulted deltaic basins, and basins with salt diapirs. It enhances biostratigraphic interpretation by providing age constraints on stratal boundaries identified through sequence stratigraphic interpretation. This can lead to a systematic prediction of other geological aspects such as the distribution of source rocks, seals, and reservoirs. Furthermore, it may also lead to the identification of new accumulations or reservoirs within existing oil and gas fields. One type of stratigraphic simulation that is often used is a stratigraphic simulation. This forward modelling method is usually applied to predict sediment distribution of a basin. In this paper, four simulation techniques (CSM, SEDPAK, DIONISOS, and SEDSIM) and their applications are presented. The models are typically applied to verify and infer the potential for hydrocarbon entrapment and accumulation in the basin. For this reason, stratigraphic simulation is useful for petroleum exploration and development. The simulation models are also useful as teaching tools for young geologists.

Deformação neógena e suas implicações na estruturação dos campos de petróleo na região de Icapuí-Ponta Grossa (CE), Bacia Potiguar emersa

In coastal cliffs at the western portion of the Potiguar Basin (so-called Aracati Platform), the Barreiras Formation, of miocene age, displays structures pointing to high strain deformation. Detailed mapping of faults and folds geometry in the Barreiras Formation leds to recognition of extensional structures (at Ponta Grossa village) and contractional oblique structures (Vila Nova, next to Icapui town), both of them related to a transcurrent system bearing NE (at these locations) and NW trends (Afonso Bezerra Fault, in the central portion of the basin). These data point to a neogene stress field which generated faults, folds and hydroplastics structures, including SL fabrics and shear zones, as well as reactivated older structures in the underlying neocretaceus sedimentary section. Reinterpretation of seismic sections from this region and other geological data at several places in the Potiguar Basin outline structures which are correlated (in style and kinematic regime) throughout the siliciclastic rocks of the Acu Formation, limestones of the Jandaira Formation and younger basalts of the Macau Formation, whose age straddles the Oligocene-Miocene boundary. This structural framework recognized at the surface has to be compatible with subsurface deformation as observed in seismic sections, which includes pulses/events of older, Neocretaceus to Paleogene age. This model has important implications as regards the structure (geometry, kinematics, age op traps) of oil reservoirs (especially the sandstones of the Acu Formation, in the Fazenda Belem Oil Field) and the processes of migration and hydrocarbon entrapment at this region of the Potiguar Basin.

Deformação neógena e suas implicações na estruturação dos campos de petróleo na região de Icapuí-Ponta Grossa (CE), Bacia Potiguar emersa

In coastal cliffs at the western portion of the Potiguar Basin (so-called Aracati Platform), the Barreiras Formation, of miocene age, displays structures pointing to high strain deformation. Detailed mapping of faults and folds geometry in the Barreiras Formation leds to recognition of extensional structures (at Ponta Grossa village) and contractional oblique structures (Vila Nova, next to Icapuí town), both of them related to a transcurrent system bearing NE (at these locations) and NW trends (Afonso Bezerra Fault, in the central portion of the basin). These data point to a neogene stress field which generated faults, folds and hydroplastics structures, including SL fabrics and shear zones, as well as reactivated older structures in the underlying neocretaceus sedimentary section. Reinterpretation of seismic sections from this region and other geological data at several places in the Potiguar Basin outline structures which are correlated (in style and kinematic regime) throughout the siliciclastic rocks of the Açu Formation, limestones of the Jandaíra Formation and younger basalts of the Macau Formation, whose age straddles the Oligocene-Miocene boundary. This structural framework recognized at the surface has to be compatible with subsurface deformation as observed in seismic sections, which includes pulses/events of older, Neocretaceus to Paleogene age. This model has important implications as regards the structure (geometry, kinematics, age op traps) of oil reservoirs (especially the sandstones of the Açu Formation, in the Fazenda Belém Oil Field) and the processes of migration and hydrocarbon entrapment at this region of the Potiguar Basin.

Improved seismic data processing and interpretation for stratistructural petroleum plays in the north of Al-Khafji area, Middle-East

Seismic data with appropriate processing tools, often come to the rescue of interpretation, minimizing the ambiguities involved in analysing complex geological situations. Stratigraphic features associated with structure, play critical role in hydrocarbon entrapment within the Middle-Late Cretaceous reservoirs in the Al-Khafji offshore area. A total of 61 square kilometres high resolution 3D OBC seismic data were acquired in the North Khafji area, with objectives to explore strati-structural traps and their associated reservoir settings. New petroleum plays are intended to be explored after integrating new 3D seismic vintage with older Al-Khafji seismic data interpretation. Present study is aimed at comparing seismic datasets that are processed by different companies. Authors examine and identify the relative merits of data attributes that are suitable for structural and strati-structural traps interpretation. The initial interpretation done during 1997, reports a possible carbonate build-up, correlatable to Gudair formation, which is equivalent to a horizon associated with Aruma-Wasia unconformity. Comparative study made between Khafji and north of Khafji field could not conclusively establish the extension of this carbonate build-up in the North-Khafji area, because of ambiguous nature of structural and stratigraphic anomalies. At places, there is inconsistency among scales of these datasets. However, based on the interpretation of the newly processed seismic data, seismic structure and attributes have been integrated and reinterpreted for scalable anomalies. Present study strongly suggests an exploration potential in the North-Khafji area and stipulates pursuing further geological studies, detailing these seismic anomalies and converting them into commercial petroleum plays in the offshore basin.

EVOLUTION AND PETROLEUM POTENTIAL OF WESTERN GREECE

This paper reviews previous data on the geological evolution of Western Greece, with special emphasis on the petroleum potential of the Pre‐Apulian zone (including new data) and the Ionian zone, the two most external portions of the Hellenide fold‐and‐thrust belt. From the Triassic to the Late Cretaceous, Western Greece constituted part of the southern passive margin of Tethys, and siliceous facies are widely associated with organic‐carbon rich deposits. Pelagic Late Jurassic units rich in marine organic matter constitute important hydrocarbon source rocks in the pelagic‐neritic Pre‐Apulian zone succession. Oil‐oil correlation with an Apulian zone oil sample (from Aquila, Italy) indicates similar geochemical characteristics. Thus, the significant volumes of oil generated by the rich and mature source rock intervals identified in the Pre‐Apulian zone are likewise expected to be of good quality. In the Ionian zone, four organic‐carbon rich intervals with hydrocarbon potential have been recorded.The tectonic history of the Pre‐Apulian zone, which is characterised by the presence of large anticlines, is favourable for the formation of structural traps. By contrast, locations suitable for the entrapment of hydrocarbons in the Ionian zone are restricted to small anticlines within largerscale synclinal structures. Hydrocarbon traps may potentially be present at the tectonic contacts between the Ionian zone and both the Pre‐Apulian and Gavrovo zones. Major traps may also have been formed between the pre‐evaporitic basement and the evaporite‐dominated units at the base of both the Pre‐Apulian and the Ionian zone successions. The degree of participation of the subevaporitic basement in the deformation of the Pre‐Apulian and Ionian sedimentary cover will determine the location and size of these traps.Various scenarios regarding the deformation of the sub‐evaporitic succession are examined in order to determine the hydrocarbon trapping possibilities of each model. The hypothesis of continental subduction (Early to Late Miocene) of the shared pre‐evaporitic basement of the Pre‐Apulian and Ionian zone eastwards of the Ionian zone is regarded favourably, as it appears to be compatible with the presence of a Phyllite ‐ Quartzite ‐ dominated (HP/LT) metamorphic unit beneath the Gavrovo‐Tripolis zone carbonates in Peloponnesus and Crete.

HYDROCARBON ENTRAPMENT IN TRIASSIC TO LATE JURASSIC RESERVOIRS IN THE TIMOR SEA, AUSTRALIA—NEW INSIGHTS

Abundant oil-filled fluid inclusions at quartz overgrowth/detrital quartz boundaries and in fractures cutting quartz grains are often used as the primary evidence of palaeo-oil columns in Triassic to Late Jurassic reservoirs in numerous wells in the Timor Sea. Based on fluid inclusion analysis of sandstone reservoirs in present oil columns, a Grains containing Oil Inclusions (GOI) value of 5% has been used as a threshold with values >5% indicating palaeo-oil columns. However, values Other indications of palaeo-oil columns are evident below and/or within GOI-defined palaeo-oil columns: good to excellent direct and cut fluorescence on cuttings and/or core, elevated resistivity and reservoir diagenesis. In the case of oil shows these hydrocarbon indications have been discounted as indicating focussed oil migration below a palaeo-oil–water contact rather than indicating a palaeo-oil column.While GOI provides valuable data to support the interpretations of palaeo-oil columns, it provides a picture at one instance in the hydrocarbon entrapment history and therefore should not be used in isolation. Other hydrocarbon indications are equally valid evidence of oil entrapment at one or more different times in the hydrocarbon entrapment history, and should be used with GOI data to provide a comprehensive picture of the evolution of a hydrocarbon trap. Case histories from wells Crux–1, in the northern Browse Basin, and Oliver–1 and Eclipse–2, in the Vulcan Sub-basin of the Timor Sea, illustrate how an integrated picture of hydrocarbon entrapment history can be developed and demonstrate that structures in the Timor Sea have undergone more than one phase of oil entrapment and leakage, with each oil phase potentially from a different oil source.

Thermal Evolution of the Ore-Hosting Isa Superbasin: Central and Northern Lawn Hill Platform

Hydrocarbon migration pathways and organic mineral matter associations were used to identify brine pathways in Paleoproterozic to early Mesoproterozoic rocks from the Lawn Hill platform, Mount Isa. Several types of organic matter are identified, and their thermal imprints are used to reconstruct the thermal history of the northern to central parts of the Isa superbasin. Three major thermal hydrothermal episodes are recognized from the organic maturation studies. Isotherm plots on a 175-km-long structural-sedimentological north-south section of the Isa superbasin highlight specific fault systems that acted as hot fluid conduits during the geologic history of the basin. Some of these systems indicate continuing activity into the south Nicholson basin, supported by the presence of low reflectance (type B) bitumen. This bitumen has not been overprinted by later hydrothermal episodes and therefore represents the latest thermal event. Along the north-south profile a general southward increase in temperature is evident. The lowest temperatures are recorded in proximity to the basin margin on the southern flank of the Murphy inlier. Thermal processes and their sequence of events in the basin are recorded by organic maturation, subsequent hydrocarbon generation, its migration and destruction coincident with transport and precipitation of minerals. As some timing and trapping mechanisms for minerals may have analogues with hydrocarbon entrapment, relative timing of processes leading to organic maturation, hydrocarbon generation and migration are utilized in this study to enhance understanding of ore-grade mineralization. In the Proterozoic successions of the Mount Isa basin multiple hydrocarbon generation events are recognized. These events record the transient passage of potential metal-bearing fluids rather than background conductive heat flow from the basement. Such hydrothermal fluids are responsible for inverse maturation profiles in the vicinity of the Termite Range fault and extreme maturation (reflectance values) up to 6 percent Ro at the Grevillea prospect. At Century, intermediate Ro values of <2 percent document the passage of fluids of less than 200 degrees C. Interaction between these hydrothermal fluids and organic matter resulted in the creation of transient microporosity that was subsequently filled with sulfide minerals, principally sphalerite (porous sphalerite texture of previous workers). Pervasive destruction of organic matter in the host sediments at Century records high water/rock ratios during this mineralizing event. Previous models for Century mineralization interpreted an in situ gas and oil accumulation at the time of mineralization. This study shows that initial maturation of organic matter at Century coincided with the influx of hydrothermal fluids responsible for mineralization. There is no evidence for the existence of an earlier hydrocarbon accumulation. In this study samples were only collected from organic matter-rich intervals, mainly shales and siltstones. Interbedded sandstones were not sampled. Therefore, it is not possible to determine which siliciclastic lithologic units transmitted the hydrothermal fluids. However, elevated reflectance values consistently occur adjacent to faults, both supersequence boundaries, surfaces of major lithologic contrast, suggesting that these features controlled fluid migration. Carbonate lithologic units sampled in this study are primarily from the Loretta supersequence (Walford Dolomite). These rocks preserve the residue of a primary migrated hydrocarbon overprinted by a hydrothermal fluid event responsible for destruction of the oil and the formation of mesophase textures characteristic of Mississippi Valley-type deposits.

West of Shetland revisited: the search for stratigraphic traps

Abstract The West of Shetland area has scope for the stratigraphic entrapment of hydrocarbons at various Jurassic to Palaeogene stratigraphic levels. Mapping and identification of such traps requires a fundamental understanding of the regional geology, the study of analogues and source kitchens, and a thorough approach to trap validation. Since 1982, 47 exploration wells have been positioned on Paleocene prospects with a significant stratigraphic component, but few have found hydrocarbons — many failing as a result of poor trap definition and overconfidence in the predictive use of amplitude anomalies. Hydrocarbon sourcing of many of the failed prospects was also poorly constrained. Few amplitude-related stratigraphic features could be tied with confidence to a viable source kitchen. The presence of a regional seal is a prerequisite ingredient for a successful Paleocene play. Many remaining undrilled, subtle prospects rely on a stratigraphic trapping component, and high-quality 3D seismic data are seen as an essential search tool. Examples of undrilled prospects are presented from the Paleocene of the northern Faroe-Shetland Basin and the Mesozoic of the East Solan Basin and Corona Ridge.

THE WHEATSTONE GAS DISCOVERY: A CASE STUDY OF TITHONIAN AND LATE TRIASSIC FLUVIAL RESERVOIRS

The Wheatstone gas discovery is located 110 km northnorthwest of Barrow Island in the Dampier sub-basin, northwest Australia. The field comprises two non-conformable and interconnected reservoir units consisting of shallow dipping, Triassic fluvial sandstones, and an overlying Tithonian transgressive sand. These units are partially separated by Late Triassic to Early Jurassic sediments.The Tithonian sand reservoir is instrumental in hydrocarbon accumulation in the Greater Gorgon Area due to its unconformable connectivity to underlying Triassic reservoirs, and its ability to act as a thief zone. It is therefore a significant component in hydrocarbon entrapment. This paper discusses the transgressive Tithonian sand palaeogeography, and environment of deposition as a predictive tool of reservoir risk assessment and play fairway geography.This study compares and contrasts the rock properties of the latest Triassic sequences and proposes the palaeogeographic make up within the basin. A review of the reservoir properties has identified differences between units which may impact the formation evaluation approach used. The thinly bedded character of the latest Triassic sequences necessitated the use of a non-traditional formation evaluation model that has improved the accuracy of the wireline predicted reservoir properties. Acquisition of probe permeability data through conventionally cored intervals identified the limitations associated with standard core plug sampling procedures, and ensured better net reservoir definition through the sequence.

Fault-seal analysis using a stochastic multifault approach

We have developed a stochastic multifault method for analysis of the impact of stratigraphic uncertainty on cross-fault leakage at sand-sand juxtapositions. This method assumes that all sand-sand juxtapositions leak across the fault. Stratigraphic uncertainty is modeled by stochastic variation of stratigraphic stacking. Structural uncertainty is addressed through variation of the input. Our objectives were to quantitatively predict the impact of uncertainties in stratigraphic and structural input and to simulate the complex system of structural spills and juxtaposition leak points that control hydrocarbon contact levels in traps with stacked reservoir systems and many faults.Three examples demonstrate how this stochastic multifault method has helped us evaluate uncertainty and understand complex leak fill-and-spill controls. The Ling Gu prospect demonstrates that widespread cross-fault leakage on two crestal faults with throw changes that exceed seal thickness causes only a single hydrocarbon column to accumulate in multiple-stacked reservoirs. This column is controlled by a juxtaposition leak point on a third, deeper fault. We have learned from examples like Ling Gu that the relative size of throw change and seal thickness is a fundamental control on the probability of cross-fault juxtapositions. An example at prospect A demonstrates the sensitivity of hydrocarbon entrapment to small faults in a sand-prone interval with thin seals. The prospect A analysis shows that if seals are thin, faults or channel incisions below seismic resolution can leak hydrocarbons out of stacked reservoirs that are interpreted as unfaulted on seismic data. This introduced significant predrill uncertainty and risk. Guntong field demonstrates that a thin sand in a juxtaposed seal interval can introduce large uncertainty in the prediction of hydrocarbon columns.These examples and many other analyses using the method demonstrate how small changes in stratigraphic and structural input to a fault-seal analysis can introduce significant uncertainty in the predicted range of hydrocarbon volumes. Such uncertainties need to be directly and systematically accounted for in a fault-seal analysis.