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Studies of near-seabed datasets show that salt tectonics controls the distribution and architecture of deep-water reservoirs in many salt-influenced basins. It is typically difficult, however, to study the distribution and stratigraphic evolution of depositional systems preserved at deeper, economically significant depths, reflecting poor seismic imaging of steeply dipping strata flanking high-relief salt structures. 3D seismic and borehole data from the Santos Basin, offshore Brazil allow us to identify a range of depositional elements that form the building blocks of three main tectono-stratigraphic phases. During the first phase, channel systems and lobes were confined within updip minibasins and to the hangingwalls of salt-detached faults. During the second phase, channel systems and lobes filled updip minibasins to bypass sediment downslope, with coarse clastic deposition then occurring in downdip minibasins, >100 km from the coeval shelf margin. Syndepositional seafloor relief caused: (i) channel system deflection and diversion around salt-cored highs; (ii) channel system uplift and rotation on the flanks of rising salt structures; (iii) lateral and frontal confinement of channel systems. During the final phase, rising salt walls dissected previously deposited deep-water systems, with MTCs deposition becoming increasingly important. Our results have important implications for post-salt prospectivity in the Santos Basin and other salt-influenced sedimentary basins, with a range of reservoirs and trapping styles present in this underexplored interval. More specifically, we show that large volumes of clastic sediment were not trapped behind the ‘Albian Gap’, a salt-controlled depocenter dominating the north-western basin margin, but were instead delivered further basinward.

Investigating the timing, structural style, and development of multiphase extensional fault systems is essential for understanding rift basin evolution and for assessment of structural trap integrity. Borehole-controlled interpretation and analysis of two-dimensional and three-dimensional seismic data sets from the eastern Dampier subbasin indicate that a northeast-trending basement weakness zone was subjected to west-northwest–east-southeast oblique extension in the latest Triassic–late Middle Jurassic, resulting in systematic segmentation of the Rosemary fault system (RFS). Temporal stress change during Cretaceous north-south extension produced complex fault systems along the RFS, including (1) east-west–trending isolated faults with maximum displacement close to their center; (2) east-west–trending abutting faults, which initially nucleated as isolated faults, later abutted against the main structure, showing large displacement accruement on the composite fault; and (3) northeast-southwest–trending splay faults characterized by systematic left-stepping segmentation, with maximum displacement occurring at the point where the splay faults deviate from the main structure. In the Miocene, the RFS was locally reactivated by northwest-southeast compression in the northeastern part of the fault system, developing a compressive fault-propagation fold at the upper tip of the inverted extensional fault. This study suggests that the style of basin boundary fault reactivation depends largely on preexisting structures and temporal stress changes. The fault reactivation style is also a significant factor in influencing basin architecture, sediment distribution, fault linkage processes, and petroleum basin prospectivity.

The occurrence of fault-related folds in extensional settings has been gaining increased recognition during the past 20 yr. Passive margins and rift basins often present intriguing structural complexities that are potential sites for the development of extensional fault–related folds. Fault-related folds are important anticlinal traps for hydrocarbon exploration, and understanding their evolution is critical for derisking the timing of trap formation and hydrocarbon generation. This study presents folds from three areas across the North West shelf (NWS) of Western Australia and aims to determine their relationship to associated extensional faults. A series of kinematic forward models are presented as well as detailed structural and stratigraphic interpretation of folding at the three locations. The models suggest each of the three examples have formed under extension that impacted the region during the Mesozoic. The modeling also highlights different characteristics of folding that are caused by fault geometry (ramp–flat) and a propagating fault tip (trishear) that can be used as diagnostic features to distinguish different fold mechanisms. Historical exploration across the NWS has targeted a relatively small number of these anticlinal traps, some of which have been successful (e.g., Marina-1 well, Petrel subbasin) and some have not (e.g., Candace-1, Sholl Island fault anticline). This paper suggests that the prospectivity of anticlinal structures should be more carefully assessed to determine whether or not they are related to extensional activity and hence likely to have formed prior to the bulk of the hydrocarbon charge. Similar structures undoubtedly exist in other basins that have experienced repeated extension.

This paper presents the potential depositional framework of sandstones and unconsolidated sand reservoirs, seals, and traps in the western part of the coastal swamp depobelt of the Niger Delta Basin, Nigeria, through integration of sequence stratigraphy and seismic imaging. The integration of well logs and biostratigraphic (foraminifera and palynological) data with three-dimensional seismic volume established the sequence stratigraphic framework, which has improved our understanding of the impact of sea-level changes in the distribution of sand facies. Four third-order seismic depositional sequences (sequences 1–4) of Serravallian deposits were identified based on the Vail stratigraphic concept. Depositional processes, structures, thickness, and seismic signatures vary in each sequence. Sequence 1, dominated by mud and very fine-grained sand facies, represents the outer shelf–shelf margin setting and has experienced shale tectonics (ductile deformation). Sequences 2 and 3 consist of alternating sand–shale facies and have experienced gravitational tectonics. Although sequence 2 represents middle shelf–inner shelf setting, sequence 3 represents inner shelf–transitional setting. Sequence 4 consists of thick fluvial–coastal plain sand facies and represents deltaic plain or continental sediments. These deposits reflect postgravitational tectonics. Within the third-order sequences are fourth-order sequences that recorded the interaction between small-scale transgressive–regressive cycles and depositional tectonics. The potential reservoirs within these sequences are stacked channel sandstones, shoreface sandstones, and heteroliths. The juxtaposition of the potential reservoirs against transgressive shales provides potential seals and traps. Structural interpretation shows synthetic and antithetic faults. In addition, event maps at various ages document structural closures that indicate the existence of possible hydrocarbon leads and prospects.

The Canning Basin is a largely unexposed and underexplored frontier basin, formed mostly in the Paleozoic. Geological knowledge of this basin is based predominantly on sparse regional “vintage” two-dimensional seismic and small three-dimensional (3-D) seismic surveys and less than 230 exploration wells. Following seismic interpretation, an integrated interpretation was completed on airborne gravity gradiometer (AGG), magnetic, seismic, well, and complementary data along the southwestern margin of the Fitzroy trough and Gregory subbasin. Seismic data were reinterpreted using AGG data to produce a better constrained geological model. A basement structure map, two intrasedimentary structure maps, and a formation distribution map were produced. The interpretation of seismic profiles, validated through 2.5-dimensional gravity gradiometer modeling, is essential to this workflow. Repeatedly reactivated west–northwest and northwest structural trends, inherited from Proterozoic orogenies, respectively delineate the Fitzroy trough and the Gregory subbasin with its northwestern structural extension into the Fitzroy trough, the Gregory subbasin trend. Subsidence occurred during two periods of extension. An asymmetric extensional system of the Fitzroy trough controlled Ordovician–Silurian deposition of the Carribuddy Group. Devonian–Carboniferous subsidence defines the Gregory subbasin trend. This Pillara extension reactivated structures in the east of the Fitzroy trough. Simultaneous activity of both extensional fault systems and growth faulting controlled the facies and thickness distribution of carbonates and clastics of the early Carboniferous Fairfield Group. The Meda and Fitzroy transpressional phases inverted faults of the Gregory subbasin trend and Fitzroy trough, producing prospects by structural interference. The improved understanding of tectono-stratigraphic relationships, including the 3-D distribution of carbonate reservoirs, benefited the planning of seismic surveys, prospect evaluation, drilling, and acreage relinquishment.

This study evaluates the petroleum prospectivity of the East Coast Basin, an element of the Hikurangi convergent margin of New Zealand. The basin tectonic environment changed from a dormant convergent margin to convergent margin around the early Miocene, likely causing a decrease in the basin thermal regime. Two end-member paleoheat flow scenarios were used to evaluate thermal maturation of two key source rocks, the Waipawa Black Shale and Whangai Formation, based on calibration to six wells across the basin using vitrinite–inertinite reflectance and fluorescence analysis, as well as Rock-Eval Tmax (the temperature at which the maximum rate of hydrocarbon generation occurs during pyrolysis analysis), thermal alteration index, apatite fission track analysis, and present-day temperatures. This study finds that paleobasal heat flow ranged between 40 and 55 mW/m−2 and decreased to 30 mW/m−2 between 15 and 5 Ma, as bracketed by the two end-member heat flow scenarios. The heat flow scenarios were applied to a palinspastically reconstructed basin and petroleum system model across Hawke Bay. We find that the two distinct heat flow scenarios cause a 3–6.5 m.y. difference in the relative timing of hydrocarbon generation across the basin. Structural events in the basin associated with convergent margin tectonics act as the main control on the timing of generation. Modeling results show transformation of kerogen to hydrocarbons began between early and late Miocene for both source rocks depending on the structural regime in the basin. The structural control on source rock maturation highlights the need for robust palinspastic reconstructions in addition to paleothermometric data to evaluate the petroleum prospectivity of convergent margin basins.

This multidisciplinary study describes the burial and exhumation history of the frontier Galilee Basin in central Queensland, Australia, with implications for understanding its geohistory and unconventional gas prospectivity. Seismic interpretation, stratigraphic mapping, and an analysis of exhumation through quantifying overcompaction show total subsidence of approximately 2 km (∼6600 ft) from the Carboniferous to the Late Cretaceous, punctuated by two major exhumation events. Triassic exhumation was less than 600 m (

The southern Canadian Rockies is an excellent area in which to examine and discuss compressional hydrocarbon traps for three main reasons: (1) the Foothills host numerous large hydrocarbon fields, many of which were discovered decades ago and continue to produce today, providing a growing subsurface database and documentation of the history of applicable structural models over time; (2) the thrust belt is well exposed and provides many outstanding examples of seismic-scale structures associated with thin-skinned fold-thrust hydrocarbon traps and play types, including surface expression of several of the producing hydrocarbon fields; and (3) many published maps and papers from the Canadian Rockies have contributed significantly over several decades to our evolving understanding of the geometry, evolution, and hydrocarbon prospectivity of thin-skinned fold-thrust belts worldwide.

Accurate definition of structural style in subsurface interpretation is critically important for understanding the deformation history of fold-and-thrust belts, as well as assessing the petroleum prospectivity of structural traps. Using two- and three-dimensional seismic reflection surveys, well data, field mapping, forward models, and balanced cross sections, we describe the structural styles across the actively deforming southern Junggar fold-and-thrust belt in northwestern China, a basin undergoing petroleum exploration and development operations. Subsurface interpretations indicate several folds in the basin overlie Jurassic normal faults that were tectonically inverted in the Late Jurassic to Early Cretaceous. Following inversion, multiple detachment levels propagated northward from the Tian Shan and formed a series of imbricated fault-related folds. The most prominent fold trend in southern Junggar consists of the Tugulu, Manas, and Huoerguosi anticlines, which trap hydrocarbons in clastic Eocene reservoirs. These structures exhibit complex internal geometries, with coeval forethrusts and backthrusts forming imbricated structural wedges. In the latest stages of deformation, and continuing at present, the uppermost thrust sheet, the Southern Junggar Thrust (SJT), truncated the backlimbs of these structural traps, implying the SJT is a tectonically active, out-of-sequence thrust. From these interpretations, we present a model for how the southern Junggar fold-and-thrust belt developed from Jurassic to present. Moreover, we detail how fold growth, fault activity, and structural style affected charge histories, trap formation, and reservoir compartmentalization. Our results have direct implications for assessment of the southern Junggar petroleum system as well as other complex fold-and-thrust belts.

Whereas the vast majority of discovered hydrocarbon reserves in Iraq reside in Cretaceous and Cenozoic reservoirs, numerous oil and gas fields have been discovered recently in deeper Jurassic and Triassic reservoirs in the Kurdistan region of Iraq. This study presents a Middle–Upper Jurassic thermal maturity map for the Kurdistan region of Iraq and demonstrates that regional first-order trends in Jurassic source rock maturity show a close correlation to the spatial distribution of oil gravities within the overlying Jurassic (and Cretaceous) reservoirs. This distribution is consistent with compartmentalization of the active source rock kitchens due to Zagros folding, resulting in relatively short-distance migration and charge of the anticlinal structures from the adjacent synclinal lows. The thermal maturity map confirms relatively low maturity over the Mosul high, where the Cretaceous and Cenozoic section overlying the source rock interval is relatively thin, and increasing maturity to the southeast as the thickness of the Cenozoic foredeep sediments increases toward the depocenter located in the southeastern Iraqi Zagros and the adjacent Iranian Zagros. The correlative trend in oil gravities is exemplified by the recent Jurassic discoveries: low to medium gravity oils (14–27° API) in Shaikan and Atrush to the northwest, light oil (39–47° API) in Mirawa and Bina Bawi, and gas condensate (55° API) in Miran West to the southeast. Understanding thermal maturity patterns and hydrocarbon fluid-type distributions will help to guide risk assessment for remaining prospectivity and future exploration drilling within the Kurdistan region of Iraq.

As one of the six subbasins in the lacustrine Bohai Bay basin, the Jizhong subbasin is characterized by a dominance of the petroleum reserves located in buried-hill traps of Paleozoic and Proterozoic marine carbonates, particularly the latter. This paper documents the revitalization of exploration of the buried-hill play and discusses other play fairways not previously considered through use of case studies. Discovery of the largest field, Renqiu field, in 1975 led to the establishment of the buried-hill play. In this play, oil derived from the Paleogene lacustrine source rocks charged into and accumulated in the underlying Proterozoic marine carbonate reservoirs. A number of buried-hill fields were discovered within a time span of ca. 10 yr in the subbasin. With more and more large buried-hill structures at depths of less than 5000 m (

In prospective basins affected by exhumation, uncertainty commonly exists regarding the maximum burial depths of source, reservoir, and seal horizons. One such basin is the Otway Basin, an important gas province in southeastern Australia, which has witnessed several exhumation events. Here, we present estimates of net exhumation magnitudes for 110 onshore and offshore petroleum wells based on the sonic transit time analyses of Lower Cretaceous fluvial shales. Our results show significant post-Albian net exhumation in the eastern onshore Otway Basin (1500 m [4920 ft]) and a generally minor net exhumation (200 m [655 ft]) elsewhere in the Otway Basin, consistent with estimates based on thermal history data. The distribution of net exhumation magnitudes in relation to mid-Cretaceous and Neogene compressional structures indicates that exhumation was dominantly controlled by short-wavelength basin inversion driven by plate-boundary forces. Deeper burial coupled with high geothermal gradients in the onshore eastern Otway Basin and along the northern basin margin during the early Cretaceous have rendered Lower Cretaceous source rocks mostly overmature, with any remaining hydrocarbons from the initial charge likely to be trapped in tightly compacted reservoirs and/or secondary (fracture-related) porosity. However, the embrittlement of these reservoirs during their deeper burial may present opportunities for the development of low-permeability plays through hydraulic fracturing where smectite clay minerals are illitized. Source rocks at near-maximum burial at present day are at temperatures suitable for gas generation, with key controls on prospectivity in these areas including the sealing potential of faulted traps and the relationship between charge and trap development.

In the Gulf of Mexico (GOM), an extensive deep-water fan system of the lower Tertiary Wilcox Group forms a significant exploration target, yet connections to equivalent-aged onshore fluvial, deltaic, and shallow-marine reservoirs are poorly documented. Using a large, three-dimensional (3-D) seismic survey (3300 mi2, 8500 km2), we examined the lower Tertiary structure and stratigraphy of the underexplored Texas coastal zone, approximately 60 mi (96 km) downdip of the paleoshelf edge and 200 mi (322 km) updip of the deep-water discoveries. Canyons are identified throughout the inferred Paleocene to upper Eocene interval near Matagorda Bay, with this study focusing on the youngest. These are typically 2–2.5 mi (3–4 km) wide and 600–1600 ft (200–500 m) deep. Main incisional axes trend downslope, and some bifurcate. Early salt movement appears to have created an irregular paleoslope topography and an altered slope gradient, thereby influencing depositional flow pathways. In a paleogeographic context, this canyon complex is interpreted to lie in a middle- to lower-slope setting and sits directly downdip of the Wilcox Group shelf-margin canyon systems. Although not all of the canyons necessarily connect updip to the shelf-edge canyons, or downdip to fan systems, they represent part of a large-scale complex along this western GOM margin that acted as a conduit to the successfully drilled, deep-water, lower Tertiary Wilcox turbidite play. These results have importance not only for the prospectivity of the Texas shelf but also for the regional understanding of the Paleocene through lower Eocene paleogeography of the GOM.

Prospect delineation in volcanic basins is commonly hampered by poor sub-basalt imaging. Recent seismic advances focusing on low frequencies have significantly enhanced structural imaging, but not the seismic resolution. Currently, the sub-basalt play is mainly a structural play. On the North Atlantic margin, success has been booked with the discovery of the sub-basalt anticlinal Corrib gas field, offshore Ireland. However, not all sub-basalt anticlines observed on seismic data are valid prospects because some of them are located directly above large igneous complexes, displaying highly overmature and overcompacted sedimentary sections with little porosity. Use of filtered gravity and magnetic data and potentially seismic velocity analysis can easily delineate and subsequently de-risk these prospects. Sill intrusion can generate subtle anticlinal traps that might be valid prospects because the thermal effect of sills is relatively limited. Thus, there is less chance of generating an overmature prospect, unless the sills occur in high numbers. Filtered gravity and magnetic data sets, in combination with local geology, can be used in the early stages of sub-basalt exploration to low-grade regions with a high amount of large intrusives. This approach is highlighted for the North Atlantic volcanic province and offshore western India. Potentially, the most prospective regions of volcanic basins are where flood basalts simply blanket sedimentary basins without intrusives in the direct subsurface. In this case, basalt thickness estimation and associated burial depth become an important parameter to estimate prospectivity. Seismic modeling suggests that it might be difficult to constrain basalt thickness from seismic sections without reliable calibration. Although an increase in volcanism in sedimentary basins generally tends to increase risks, proper integration of geophysical and geological data should be able to better evaluate volcanic basins.

The northern part of Honshu Island contains the major petroleum resources of Japan. The source rocks mainly comprise a sequence of Miocene marine mudstones that are overlain in places by thick Pliocene and Pleistocene sediments. In the past, mainly vitrinite reflectance analyses have been used to evaluate thermal maturities of these rocks. However, vitrinite reflectance suppression caused by compositional variation of vitrinite is common in marine-deposited rocks, and therefore, modeled estimations of the extent of petroleum generation from the Japanese sequences could be in error. Fluorescence alteration of multiple macerals (FAMM) analysis is a method that aids in solving the problem of vitrinite reflectance suppression and gives improved evaluations of thermal maturity. Combined vitrinite reflectance and FAMM analyses of potential source rock sequences intersected by the Ministry of International Trade and Industry (MITI) Shin-Takenomachi and MITI Nishi-Kubiki wells of the Niigata Basin and the MITI Honjo-Oki and MITI Yuri-Oki-Chubu wells of the Akita Basin show that vitrinite reflectance suppression is common in the Neogene source rocks. This leads to major differences between the depth profiles for vitrinite reflectance and for FAMM-derived, equivalent vitrinite reflectance. On the basis of vitrinite reflectance, the thermal maturity and hence, the petroleum source rock potential is underestimated for the Miocene Noudani Formation of the Niigata Basin and the Pliocene Funakawa and Miocene Onnakawa and Nishikurosawa formations of the Akita Basin. The new thermal maturity data indicate that these formations would have generated more oil than previously thought, such that petroleum prospectivity for areas including these sequences should be reassessed.

Fault sealing is one of the key factors controlling hydrocarbon accumulations and trap volumetrics and can be a significant influence on reservoir performance during production. Fault seal is, therefore, a major exploration and production uncertainty. We introduce a systematic framework in which the geologic risk of faults trapping hydrocarbons may be assessed.A fault may seal if deformation processes have created a membrane seal, or if it juxtaposes sealing rocks against reservoir rocks, and the fault has not been reactivated subsequent to hydrocarbons charging the trap. It follows from this statement that the integrated probability of fault seal can be expressed as {1 − [(1 − a)(1 − b)]} (1 − c), where a, b, and c are the probabilities of deformation process sealing, juxtaposition sealing, and of the fault being reactivated subsequent to charge, respectively. This relationship provides an assessment of fault-seal risk that integrates results from the critical parameters of fault-seal analysis that can be incorporated into standard exploration procedures for estimating the probability for geologic success. The integrated probability of fault seal for each prospect can be visualized using the fault-seal risk web, which allows rapid comparison of success and failure cases through construction of prospect risk web profiles.The impact of uncertainty (U) and the value of information (VOI) for each aspect of fault sealing on the overall fault-seal risk may be determined via the construction of data webs and the relation U = [1 − {(nw) / n}] 100, where nw is the value given to each data web parameter and n is the number of data web components. For example, the data web components required to assess fault reactivation risk are the orientation and magnitude of the in-situ principal stresses, pore pressure, fault architecture, and the geomechanical properties of the fault.Risking of the Apollo prospect, Dampier subbasin, North West shelf, Australia is presented as a worked example. Fault-seal risking for the Apollo prospect has been conducted on 10- and 100-ft oil columns to allow integration with volumetric probabilistic statements. The critical parameter for fault-seal risking at the Apollo prospect is the ability of disaggregation zone faults (low shale gouge ratio fault gouge) to support increasingly large hydrocarbon columns. Evaluation of the individual components for Apollo fault sealing indicates a = 0.3 (10-ft column) and a = 0.1 (100-ft column), b = 0.2, and c = 0.1. The overall probability of the Apollo trap-bounding fault sealing a 10-ft oil column is 0.4 or 40% (seal condition moderately unlikely). The likelihood that the fault seals oil columns greater than 100 ft is 0.3 (seal condition unlikely). Data web error margins for the Apollo prospect are 20% (juxtaposition uncertainty), 26% (fault-rock process uncertainty), and 27% (fault reactivation uncertainty). Recalculating each parameter by its uncertainty, for a 10-ft oil column, the upper value of integrated fault-seal risk is 0.5 (seal condition intermediate), and the lower value is 0.3 (seal condition unlikely). The upper value of integrated fault-seal risk for a 100-ft oil column is 0.3 (seal condition unlikely), and the lower value is 0.2 (seal condition very unlikely). The variation in the Apollo final risk calculation reflects the lack of prospect-specific data. The greatest VOI benefit for Apollo fault-seal prospectivity is sedimentary architecture data.

The Taranaki Basin contains most of New Zealand's commercial hydrocarbon reserves. The southern parts of the Taranaki Basin underwent inversion during the late Miocene, with published AFTA (apatite fission-track analysis) and vitrinite reflectance data suggesting approximately 2.5-3 km of section eroded from the structure on which the Fresne-1 well was drilled, consistent with estimates from reconstructions based on seismic sections. The well-constrained tectonic and thermal history framework for this well section, established by earlier studies, provides an ideal test bed for the thermochronological technique of apatite (U-Th)/He dating. Helium ages determined in apatites from the earlier AFTA study decrease from about 6 Ma at about 400 m depth to about 1 Ma at 2465 m. Although these results are qualitatively consistent with late Miocene cooling, quantitative modeling of (U-Th)/He ages based on best-fit thermal histories derived from new AFTA analyses (using improved methods) suggests that cooling was protracted, involving accelerated cooling during the Pliocene, possibly indicating a discrete Pliocene inversion phase. Integration of AFTA and (U-Th)/He dating can provide improved thermal history constraints in sedimentary basins, particularly on cooling rates and/or resolution of multiple thermal events. By independently defining the timing of peak maturation in relation to formation of potential trapping structures, this information offers the potential for improved assessment of hydrocarbon prospectivity and reduced exploration risk.

Oil-bearing fluid inclusions in sandstone cores and cuttings represent hidden oil shows. The frequency of quartz grains containing these inclusions (the GOI number) reflects the maximum paleo-oil saturation experienced in a sandstone reservoir irrespective of the present fluid phase. Samples that have been exposed to high oil saturation have GOI numbers at least one order of magnitude greater than samples that have demonstrably low oil saturation. In this way, these fluid inclusion data can be used to identify paleo-oil columns and to map original oil-water contacts in wells where oil has been displaced by a later gas charge. Moreover, the use of detailed GOI mapping to accurately define the location of the original oil-water contact allows the height of the paleocolumn to be determined and an estimate to be made of original oil in place. The Oliver oil and gas discovery, located in the Timor Sea, Australia, presently contains a hydrocarbon column of 178.5 m, composed of 164 m of gas over a 14.5 m oil leg, and is filled to spillpoint. In well Oliver-1, GOI mapping has delineated a gross paleo-oil column of between 99 and 132 m within the present gas leg. This corresponds to original oil in place of up to 200 million bbl, considerably greater than the 45 million bbl of oil presently reservoired. The displacement of up to 155 million bbl of oil from this structure has high-graded the prospectivity of tilted fault blocks updip from the Oliver structure. GOI mapping is an innovative approach to reservoir characterization that can reliably detect paleo-oil accumulation in hydrocarbon traps that are presently filled by gas. These data allow the oil-leg potential of both gas discoveries and nearby untested structures to be addressed in a quantitative manner before additional drilling is commissioned.

Recent discoveries of oil and gas in Triassic reservoirs of the Ghadames basin, eastern Algeria, suggest that similar potential exists to the east, in the southern Tunisian part of the province. For decades, southern Tunisia has remained an underexplored part of the basin, in large part owing to older geological interpretations that focus on Paleozoic reservoirs and to limitations in seismic data quality, resulting from statics problems, that have rendered trap identification inaccurate or tenuous. New analyses of previously and recently acquired geological and geochemical data, as well as improvements in seismic data acquisition and processing, have begun to reverse older notions regarding limited hydrocarbon presence in southern Tunisia. Log correlations indicate that productive, sand-rich intervals of the major Triassic reservoir in the region, the Trias Argilo Greseux Inferieur (TAGI), can be correlated over large distances, suggesting significant continuity into lightly drilled and undrilled areas. Analyses of geochemical data reveal a more complex, multistage history of hydrocarbon maturation and migration than previously believed. Much greater volumes of petroleum have been generated and a larger variety of traps have been created than can be accounted for by older interpretations. Where added to the use of new field and processing parameters for seismic surveys, these factors have together led to important, upgraded evaluations of basin potential in southern Tunisia.

Seismic stratigraphic analysis of the continental shelf north of the Falkland Islands confirms that it is dissected by a significant extensional fault system that broadly defines the North Falkland Basin. The basin comprises a series of extensional subbasins that developed during two distinct rift episodes. Analysis of structural styles shows that while extension occurred predominantly on a series of planar normal faults with changes in rift polarity in northern areas, the southern portion of the basin has listric faults that sole out along preexisting thrusts. After rifting, the basin largely underwent postrift thermal subsidence with the passive infill of remnant topography; however, evidence exists for at least two uplift events affecting the postrift sediments. The earlier period of uplift tilted the basin to the south, resulting in the formation of a southerly prograding forced regressive wedge; the later episode of uplift tilted the basin northward, resulting in truncation of earlier strata and minor compressional reactivation and inversion in southernmost parts of the basin. The later tilting allows for the possibility that the original rift system once extended across the Falkland Islands. Although the lack of well control does not permit a comprehensive assessment of hydrocarbon plays, the seismic data do at least demonstrate the trapping potential of the basin. Interpreted structural and depositional styles found within the prerift, synrift, and postrift sequences are similar to those found in proven hydrocarbon provinces such as the North Sea and the Gulf of Suez. The success or failure of the frontier hydrocarbon province thus is likely to depend upon factors other than structural ones.

Although commonly reservoired within Tertiary rocks, hydrocarbons in eastern Indonesia have generally been sourced from Mesozoic sediments deposited on the continental margin of northern Australasia. Fragments of this margin are now widely dispersed as allochthonous terranes throughout the area, one of the most far traveled examples being the island of Buton, southeast of Sulawesi. Asphalt reserves on Buton support a significant local industry and exploration continues for oil and natural gas. In common with other prospective Australian-derived terranes around the margins of the Banda Sea, Buton is now separated from Australia by the active plate boundary marked by the Java Trench and the collision trace along the Timor, Tanimbar, and Seram troughs. Buton differs from these other terranes in its distance from that boundary and its consequent insulation from the effects of the Pliocene-Pleistocene collision between Australia and the Banda arcs. Reconstruction of the geological history of the Buton terrane thus has an important role in guiding future exploration in the other Australasian fragments in eastern Indonesia. Geophysical studies of the Buton region have used seismic reflection, gravity, and magnetic (including paleomagnetic) techniques. Seismic reflection images generally record extension rather than compression as dominating the recent history of the area. Gravity data define the present-day western limits of the Buton terrane and suggest that in the east the terrane includes the almost entirely submerged Tukang Besi platform. The gravity surveys also demonstrate that the ophiolitic rocks exposed on Buton are not attached to deep roots, but are thin and isolated overthrust sheets. Therefore they do not mark a terrane boundary and their presence has little bearing on the prospectivity of the area. Paleomagnetic results document the independent movements of thrust sheets on Buton during the Pliocene-Pleistocene. The combined data from Buton record its separation from Australia as part of a microcontinental block in the Jurassic or Late Triassic, followed by collision with the Eurasian margin in southeastern Sulawesi in the Oligocene or early Miocene. Collision was followed by extension (as in Sulawesi itself) producing minor separation of Tukang Besi from Buton and much greater dispersion of other fragments of the microcontinent, some of which have since been incorporated in the new collision zone in the Outer Banda arc. The oil seeps and asphalt deposits of Buton are proof that hydrocarbons in the Banda arc fragments can be sourced from within these fragments and are not necessarily derived from the underthrusting Australian margin.

Although the majority of the oil reserves contained in the Ninian field are being produced from tilted Middle Jurassic sandstones of the Brent Group, significant volumes of oil have also been discovered within a poorly documented, subtle structural trap that lies in the immediate footwall to the field's controlling, eastern boundary fault. Integration of well data and the interpretation of seismic surveys allow the definition of an area characterized by major footwall degradation. The data demonstrate that the 1.25-mi (2-km) wide area affected lies to the east of the zone of Brent Group truncation, along the whole 15-mi (25-km) length of the field. A combination of sedimentary and stratigraphic information shows that the degradation and products obtain a thickness that locally exceeds 450 ft (126 m). The degradation process appears to have been triggered by accelerated extension during the Callovian-early Oxfordian deposition of the Heather Formation. The development of pronounced fault terraces due to footwall collapse ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received February 26, 1996; revised manuscript received August 12, 1996; final acceptance December 24, 1996. 2Department of Geology and Geophysics, The University of Edinburgh, Kings Buildings, West Mains Road, Edinburgh, EH9 3JW Scotland; e-mail: jru@glg.ed.ac.uk 3Chevron (UK) Ltd., Ninian House, Crawpeel Road, Aberdeen, AB12 3LG Scotland. 4Department of Earth Sciences, University of Manchester, Oxford Road, Manchester, M13 9PL England. We would like to thank the Ninian Partners [Chevron UK Ltd., Murphy Petroleum Ltd., Oryx UK Energy Company, Sands Petroleum (formerly NESTE North Sea Ltd.), Sun Oil Britain Ltd., and Ranger Oil] for permission to publish this article. However, the views expressed here are ours and are not necessarily those of Chevron or the Ninian Partnership. Help was received from Rick Davis, Robert Heming, Bryan Man, Bill Higgs, Andrew Harding, and John Connor of Chevron. Gerry White is thanked for drafting the diagrams. Interpretations carried out using GeoQuest ies and iesx software mounted on Edinburgh's Seismic Workstation facility were supported by The Petroleum Science and Technology Institute (PSTI), Norsk Hydro, Shell Expro, and Esso Exploration and Production (UK) Ltd. The study forms part of a wider research program studying the occurrence and effects of fault scarp degradation and subtle stratigraphic trap formation in the Brent province currently being supported at The University of Edinburgh by a Natural Environmental Research Council (NERC) Realising Our Potential Award (ROPA) Grant, GR3/R9521. Finally, we would like to acknowledge AAPG reviewers Alan Roberts and J. Brint for helpful and constructive comments.

The Neogene turbidite systems of northern Green Canyon and Ewing Bank lease areas in the northern Gulf of Mexico are a major exploration play. The regional sequence stratigraphic framework for this area has been interpreted to help define potential areas for future exploration. The study area includes 17 fields/discoveries primarily in turbidite-related reservoirs. Once the sequence stratigraphic framework was established, the existing fields and potential prospects can be quickly evaluated in terms of sequence stratigraphy. Good potential for future exploration exists both in sub-salt prospects and in the deeper water portions of the area. For example, two discoveries (GC 200/244, 506) have been made during the past year. Two main potential reservoir intervals have been identified, which reflect different Winds of turbidite systems based upon lithologies and seismic facies. Lower Pliocene sediments (5.5 to 3.0 Ma) consist of sand-rich turbidite systems (up to 50 % sand in some sequences). Sand bodies are interpreted to be a really widespread sheet and amalgamated sheet sands. The lower Pleistocene interval (1.9 to 0.7 Ma) is predominantly shale-rich with localized thick sands developing in channel-levee systems and unchannelized sands (basin-floor fans). Most of the reservoirs in the area occur within this interval.

The Torquay Sub-basin is located in the offshore part of the eastern Otway Basin, some 50km southwest of Melbourne. Three wells, all dry holes, were drilled between 1967 and 1992. Nerita-1 drilled in 1967 tested Eocene and Early Cretaceous reservoirs in a Miocene anticline. Snail-1 drilled in 1972 was not a valid structural test, and Wild Dog-1 drilled in 1992 tested Late Eocene sands in an Oligocene inversion faulted anticline sourced from Early Cretaceous coals. The area was assessed by previous explorers as lacking effective source. Work currently underway indicates these wells were dry because of lack of migration pathways to the Tertiary. To the west, significant gas has been discovered in Late Cretaceous reservoirs offshore at Minerva-11 and LaBella-1, and onshore in wells in the Port Campbell Embayment. In the Bass Basin to the south, there have been consistent oil, condensate and gas shows. Geochemical analysis of the Early Cretaceous Eumeralla Formation and Casterton beds throughout the Otway Basin demonstrate they contain source rocks capable of generating both oil and gas. Our study indicates that early Cretaceous sandstones with porosities better than 20%, may be present at depths of less than 2000m in the Torquay Sub-basin in tilted faultmore » blocks. Source would be from down-dip lacustrine shales of the Casterton Beds. The general basement high area in which this play is developed is some 15km by 15 km with up to 400m of relief.« less

Depositional systems in deep-water basin margins can be classified on the basis of grain size and feeder system into 12 classes: mud-rich, mud/sand-rich, sand-rich, and gravel-rich "point-source submarine fans;" mud-rich, mud/sand-rich, sand-rich, and gravel-rich "multiple-source submarine ramps;" and mud-rich, mud/sand-rich, sand-rich, and gravel-rich "linear-source slope aprons." The size and stability of channels and the organization of the depositional sequences decreases toward a linear source as does the length:width ratio of the system. As grain size increases, so does slope gradient, impersistence of channel systems, and tendency for channels to migrate. As grain size diminishes, there is an increase in the size of the source area, the size of the depositional sys em, the downcurrent length, the persistence and size of flows, fan channels, channel-levee systems, and in the tendency to meander and for major slumps and sheet sands to reach the lower fan and basin plain. The exact positioning of any one depositional system within the scheme cannot always be precise, and the position may be altered by changes in tectonics, climate, supply, and sea level. However, the models derived from each system are sufficiently different to significantly affect the nature of petroleum prospectivity and reservoir pattern. Understanding and recognizing this variability is crucial to all elements of the exploration-production chain. In exploration, initial evaluations of prospectivity and commerciality rely on the accurate stratigraphic prediction of reservoir facies architecture, and trapping styles. For field appraisal and reservoir development, a similar appreciation of variability aids reservoir description by capturing the distribution and architecture of reservoir and nonreservoir facies and their impact on reservoir delineation, reservoir behavior, and production performance.

Triggered by the discovery of the giant Groningen gas field (2700 bcm) in 1959, the hydrocarbon exploration in the Netherlands was strongly boosted. Over the last decades, the country has proved to be a very prolific hydrocarbon province, particularly for natural gas. Supported by the favorable exploration climate, exploration effects have been at a high and sustained level. Well over 250 gas reservoirs have been discovered throughout the stratigraphic column in various plays. Field sizes range from medium (about 50 bcm) down to very small (2 bcm or less). Total initial reserves in these fields are approximately 1100 bcm. A mature stage of exploration has been reached in many areas. However, within a few years, virtually all production acreage and large parts of the exploration acreage in the Netherlands will have been covered with three-dimensional (3-D) seismic. Improvement of exploration drilling efficiency has already been shown in terms of increased technical success rates. Moreover, the use of 3-D seismics has proven cases of additional prospectivity undetected before. Here, a major possibility, and challenge, for finding future incremental reserves is present. On the development side, nearly all large- and medium-size gas fields have, or shortly will, come on stream. However, themore » majority of the relatively large population of small and marginal fields is still undeveloped. Here, the challenge is to reduce economic limits by a.o. further expansion of infrastructure and the application of modern marginal field development technology. Actual examples illustrate the possibilities to increase the developed reserves.« less

In 1988, 550 square km of 3D seismic data were acquired in the Sur Del Lago area. The aims of the survey were (1) To better define structures already identified from the existing 1 [times] 1 km 2D seismic grid at the level of potential Cretaceous limestone reservoirs and (2) To further study the prospectivity of potential structural and stratigraphic traps within the Tertiary section. Detailed interpretation of the 3D survey using an interactive workstation led to an improved structural definition at the Cogollo limestone level and the identification of fault related inversion lineaments and basement related Cretaceous limestone structures. Based upon the new seismic interpretation a 4 well exploration project was planned. The new program commenced with the drilling of exploration well SLA-7-IX in 1991 which proved commercial amounts of hydrocarbons in the western part of the area. Detailed information collected from the exploration wells includes a comprehensive electric log suite, ditch cuttings and vertical seismic profiles. The information is being used as detailed lithological, stratigraphic and seismic data input for velocity modeling, ray trace modeling, seismic attribute analysis, and reservoir characterization software in order to further understand the structural and stratigraphic potential of the area.

Apatite fission track analysis (AFTA) has been applied to samples from four hydrocarbon well sections to study the thermal and tectonic history and the hydrocarbon prospectivity of the southern part of the Taranaki basin (New Zealand). Data from three of the wells (1 Fresne, 1 North Tasman, 1 Surville) show that the successions were exposed to higher temperatures in the past through deeper burial. Cooling from elevated paleotemperatures was effected by late Miocene uplift and erosion of 3.0 + or - 0.3 km of section in 1 Fresne, < or = 2.0 + or - 0.5 km in 1 Surville, and 1.0 + or - 0.3 km in 1 North Tasman. In the fourth well, 1 Kupe, formations are currently at their maximum temperatures since deposition. AFTA provides unique constraints on the timing of hydrocarbon generation in relation to trap formation. The proposed source rocks in 1 Fresne passed through the oil formation window (100-150 degrees C) and into the zone of gas production (150-220 degrees C) during the middle Miocene, prior to the formation of potential trapping structures. Those in 1 North Tasman passed into the oil formation zone about the same time, and source rocks in 1 Surville have probably never been heated enough to produce oil. AFTA indicates considerable prospectivity remains in the region of 1 Kupe, where generation would have occurred after trap formation.

The Late Triassic-Early Jurassic rift basins of Iberia, offshore eastern Canada, and the continental shelf of western Europe are fragments of a formerly coherent northeast-trending rift system that probably formed as a result of tensional stress between Europe, Africa, and North America. The separation of Europe, North America, and Iberia was preceded by a Late Jurassic-Early Cretaceous rifting phase that is clearly distinct from the earlier Mesozoic rifting episode and was little influenced by it. The two periods of rifting are separated by a Middle Jurassic relatively tectonically quiet period. The distribution of hydrocarbon finds within the rift basin suggests that the best prospects are in areas where the two rifting episodes are superimposed. Lack of mature source r cks in the later Mesozoic rift basins and an unfavorable temporal relationship between hydrocarbon generation and tectonic activity in the early Mesozoic basins are proposed as explanations for the apparently poor hydrocarbon prospectivity of large areas of the Mesozoic basins.

Callovian-Tithonian rocks of south Iraq are deposited of a major regressive sedimentary cycle. It began with the deposition of a basinal black bituminous shale and carbonates of the Naokelekan formation, which graded southwestwardly into a neritic, oolitic carbonate of the Najmah Formation and finally terminated by a lagoonal-supratidal dolomite and anhydrite of the Gotnia-Barsarin Formations. This sedimentary cycle is located on the same Tethyan shelf, at similar depth, deposited under the same paleoenvironments and is chronologically correlative with the Tuwaiq-Hith cycle of eastern Saudi Arabia. In the study area, drill-stem tests have proved the Najmah as an oil producer and the Gotnia as a cap rock and have pointed out the basinal black shales and carbonates of the Naokelekan and the underlying Bathonian Sargelu Formations as potential sources of hydrocarbons. In this study, the Upper Jurassic lithofacies have been, structurally, geothermally, and hydrodynamically mapped and evaluated for source, reservoir, and cap rock potentials. Patterns, styles, and histories of structural growth of structural anomalies have been evaluated and clustered into areas with identical structural style and growth history. Prospectivity was rated by projecting incipient structural growths, paleoextent of geothermal source rock maturation, and probably paleodirections of fluid migration on a seriesmore » of paleostructural maps which illustrates the evolution of these variables against a background of Upper Jurassic facies maps.« less

The geology of northern Morocco is dominated by the mountainous areas of the Rif and the Prerif. These mountains form the southern half of the Rif-Betic arc. The surface geology of the Prerif area is characterized by the allochthonous mass of the Prerif nappe, which is variously described as a tectonic melange, an olistostrome, or a combination of the two. It is structurally extremely complex and this fact has, in the past, deterred international companies from exploring for oil in the area. Recently acquired seismic data shed some light on the structure within the Prerif nappe; it tends to support a tectonic origin rather than one based on gravity drive. In this framework, a model is proposed for the tectonic development of the Rif/Prerif in particular and the Rif/Betic arc in general, based upon the interaction of the Iberian, Moroccan, and Alboran plates from the Triassic to the Neogene. The seismic data also show, however, that a sizeable Mesozoic trough exists beneath the mass of the Prerif nappe. In addition, several piggyback basins are developed above the nappe. Therefore, considerable potential for oil and gas discoveries exists both above and below the nappe.

The prospectivity of the Papuan Basin has been appreciated, since oil seeps were first discovered in 1911. Initially, the mountainous terrain, a deeply karstified limestone surface covered with tropical rainforest, fed by 300 inches of rain each year, restricted access to the adventurous. Early exploration was focussed along the coastline and river systems, with only limited success. The development of helicopter transportable rigs during the 1970s was the technological advance that led to success, as the crests of anticlines became accessible to the drill. Even so, the lack of seismic due to severe terrain conditions and structural complexity, still constrains our ability to image trap. Despite these limitations, the oil discovery at Lagifu-2 in 1986, led to the development of the Kutubu Field by a Chevron led joint venture, with first oil in 1992. The Kutubu Field was developed at a cost of US$ 1 billion. Reserves are in excess of 250 mmbo with production currently at 1,00,000 bopd. PNG's second oil development will be the Gobe / SE Gobe Fields, also in the Papuan Thrust Belt, and thought to contain around 100 mmbo. Discovered in the late 1980s, the field is expected to produce 25 000 bopd from 1997.more » Significant volumes of gas have been discovered in the Highlands at Hides, where 3 wells have now confirmed a gas column in excess of 1 km. Additional large gas discoveries have been made in the Papuan Basin, highlighting the potential for PNG to become a long term LNG s producer.« less