Active Petroleum System Research Articles

Australia's onshore basin inventory: volume I

Following the publication of Geoscience Australia Record 2014/09: Petroleum geology inventory of Australia’s offshore frontier basins by Totterdell et al (2014), the onshore petroleum section of Geoscience Australia embarked on a similar project for the onshore Australian basins. Volume I of this publication series contains inventories of the McArthur, South Nicholson, Georgina, Amadeus, Warburton, Wiso, Galilee, and Cooper basins. A comprehensive review of the geology, petroleum systems, exploration status, and data coverage for these eight Australian onshore basins was conducted, based on the results of Geoscience Australia’s precompetitive data programs, industry exploration results, and the geoscience literature. A petroleum prospectivity ranking was assigned to each basin, based on evidence for the existence of an active petroleum system. The availability of data and level of knowledge in each area was reflected in a confidence rating for that ranking. This extended abstract summarises the rankings assigned to each of these eight basins, and describes the type of information available for each of these basins in the publically available report by Carr et al (2016), available on the Geoscience Australia website. The record allocated a high prospectivity rating for the Amadeus and Cooper basins, a moderate rating for the Galilee, McArthur and Georgina basins, and a low rating for the South Nicholson, Warburton and Wiso basins. The record lists how best to access data for each basin, provides an assessment of issues and unanswered questions, and recommends future work directions to lessen the risk of these basins in terms of their petroleum prospectivity. Work is in progress to compile inventories on the next series of onshore basins.

The role of seal integrity in the Vlaming Sub-basin (Perth Basin) for preservation of hydrocarbon accumulations

SUMMARY The offshore Vlaming Sub-basin, located in the southern part of the Perth Basin, is a Mesozoic depocentre estimated to contain over 12 km of sediments. It has several potential source rock intervals, good reservoir and seal pairs and an active petroleum system. The reasons for a lack of exploration success in this basin have been re-assessed by analysing fault reactivation and signs of hydrocarbon seepage. A recently completed study integrated structural mapping with analysis of fluid inclusion results. New data and interpretations show that a number of synrift faults with signs of reactivation in seismic data also have Fluid Inclusion Stratigraphy (FIS) anomalies above the regional seal. Many previously identified plays rely on the post-rift South Perth Shale for a seal. Our analysis suggests that many faults were reactivated after the deposition of the South Perth Shale, with some showing signs of present-day reactivation. Reactivated faults provided migration pathways for generated hydrocarbons; therefore, no accumulations were formed at these locations. The study provides insight into the location of leaky structures and areas with potentially valid plays in the Vlaming Sub-basin.

The Paleozoic Hudson Bay Basin in northern Canada: New insights into hydrocarbon potential of a frontier intracratonic basin

The Hudson Bay Basin is the largest intracratonic basin in North America, although it is the only one without any proven hydrocarbon reserves. The stratigraphic succession that fills the basin consists mainly of Paleozoic strata, with a maximum preserved thickness of about 2500 m (8202 ft). The Paleozoic succession includes Ordovician to Devonian shallow marine carbonates, reefs, and shales with locally thick Devonian evaporites. The Paleozoic strata are locally unconformably overlain by a thin Mesozoic and Cenozoic cover of nonmarine and marine strata. From 1964 to 1985, over 46,000 line-km (28,600 mi) of seismic reflection data were acquired, and four onshore and five offshore exploration wells were drilled. The data acquired at that time led to pessimistic conclusions on source rocks and the thermal rank of the basin and resulted in the stoppage of exploration activities. However, hydrocarbon shows or indicators were identified in well log data and seismic reflection profiles. The likelihood of an active petroleum system has also been recently supported by recognition of pockmarks on the seafloor and possible marine oil slicks identified on satellite images. New studies of geological, geophysical, and biostratigraphic data reveal that the Hudson Bay Basin had an irregular subsidence and uplift history. Syntectonic deposition occurred during the Late Ordovician(?) to Early Devonian and sag-basin deposition during the Middle to Late Devonian. The basin contains four unconformity-bounded sequences, with significant depocenter migration over time. Analyses of petroleum-system data indicate the Hudson Bay Basin has higher petroleum potential than previously considered. Porous platform limestones, reefs, hydrothermal dolomites, and siliciclastics form potential hydrocarbon reservoirs. Upper Ordovician organic-rich shales with type II-S organic matter are recognized at several locations in the basin. Newly acquired organic matter reflectance and Rock-Eval data indicate Ordovician–Silurian strata locally reached the oil window. Basin modeling demonstrates significant potential for oil generation and expulsion from Ordovician source rocks. Five petroleum play types are identified in the Hudson Bay Basin, including an untested fault-sag or hydrothermal dolomite play. The synthesis of the petroleum system information indicates that the Hudson Bay Basin is, at least locally, prospective for oil accumulations.

Chronology and backtracking of oil slick trajectory to source in offshore environments using ultraspectral to multispectral remotely sensed data

Offshore natural seepage confirms the occurrence of an active petroleum system with thermal maturation and migration, regardless its economic viability for petroleum production. Ocean dynamics, however, impose a challenge for correlation between oil seeps detected on the water surface and its source at the ocean floor. This hinders the potential use of seeps in petroleum exploration. The present study aims to estimate oil exposure time on the water surface via remote sensing in order to help locating ocean floor seepage sources. Spectral reflectance properties of a variety of fresh crude oils, oil films on water and oil–water emulsions were determined. Their spectral identity was used to estimate the duration of exposure of oil–water emulsions based on their temporal spectral responses. Laboratory models efficiently predicted oil status using ultraspectral (>2000 bands), hyperspectral (>300 bands), and multispectral (<10 bands) sensors covering near infrared and shortwave infrared wavelengths. An oil seepage recorded by the ASTER sensor on the Brazilian coast was used to test the designed predictive model. Results indicate that the model can successfully forecast the timeframe of crude oil exposure in the ocean (i.e., the relative “age” of the seepage). The limited spectral resolution of the ASTER sensor, though, implies less accurate estimates compared to higher resolution sensors. The spectral libraries and the method proposed here can be reproduced for other oceanic areas in order to approximate the duration of exposure of noticeable natural oil seepages. This type of information is optimal for seepage tracing and, therefore, for oceanic petroleum exploration and environmental monitoring.

Seismic Imaging of Seabed Morphology Offshore Niger Delta

3D seismic data have been used to describe the seabed morphology offshore Niger Delta in the Gulf of Guinea. The seabed morphology is characterized by bathymetric ridges and grooves related to gravity-driven thrusting and folding in the Niger Delta compressional domain, numerous canyons, and fluid venting structures with morphologies similar to pockmarks. The pockmarks are found predominantly parallel to canyon margins, along the axis of bathymetric grooves and ridges and in places related to discontinuities on the seafloor. The densest concentration of pockmarks along canyon margins is probably due to active seepage of hydrocarbon fluids from shallow and or deep subsurface reservoirs. The large scale occurrence of pockmarks is a strong evidence of fluid migration processes and perhaps the existence of an active petroleum system in the area.

Reservior quality of intrabasalt volcaniclastic units onshore Faroe Islands, North Atlantic Igneous Province, northeast Atlantic

The Paleocene and Eocene strata in the western part of the Faroe-Shetland Basin contain abundant volcanic and volcaniclastic rocks. Recently, hydrocarbon discoveries have been made in reservoirs of siliciclastic origin in intra- and post-volcanic strata in the central Faroe-Shetland Basin that show an active petroleum system is present in the volcanic affected area. The siliciclastic reservoirs are present in the same stratigraphic levels as the volcanic and volcaniclastic rocks, and in places, the siliciclastics and the volcanics interfinger. The assumption from published studies so far, based on limited data, is that the volcanic and volcaniclastic rocks are nonreservoir facies. In this study, based on studies of 140 core samples representing more than 70 different volcaniclastic interbeds from onshore Faroe Islands, it is demonstrated that 18 samples are in the helium (He) porosity range of 20% to 43% and a gas permeability range of 1.0 to 110 md, and among these samples, 7 are of epiclastic and 11 of pyroclastic origins. These 18 samples have been investigated further. Among the seven samples of epiclastic origin, five stem from Glyvursnes-1 well Argir Beds that is a fluvial deposit located close to a fault. These samples are correlated and compared with the wireline logs from Glyvursnes-1. Based on this comparison, it is found that the porosity of the Argir Beds is best estimated from wireline logs using (P-wave seismic velocity), (S-wave seismic velocity), or resistivity logs. Onshore samples are used as Faroese offshore volcaniclastic intervals are represented by a few confidential samples where the stratigraphic level is uncertain. The onshore samples have been taken from 29 geotechnical (made related to tunnel building, etc.) and 2 scientific (made related to research of the geology) boreholes and represent almost the entire stratigraphic volcaniclastic interval onshore Faroe Islands. In addition, they also cover most of the Faroe Island area geographically. The intervals where the samples are taken represent both in situ and transported material. Three units are ascribed to fluvial, mass flow, and swamp deposit environments, whereas the remaining beds are most likely pyroclastic deposits. The He porosity, gas permeability, and grain density were measured, and in addition, thin sections of all the samples have been produced.

Discovery of organic-rich black shale xenolith from kimberlite on the Hall Peninsula, Nunavut and its implication for petroleum potential in Cumberland Sound

The Chidliak kimberlite province covers an area of 40 × 70 km on the eastern Hall Peninsula, southeastern Baffin Island, Nunavut, between Frobisher Bay and the Cumberland Sound (Fig. 1). The eastern Hall Peninsula is an Archean gneissic terrain, into which all the Late Jurassic–Early Cretaceous aged kimberlites (156.7–139.1 Ma; Heaman et al., 2012) intruded. At present, there is no consolidated Phanerozoic sedimentary cover on the Hall Peninsula; however, a great number of sedimentary rock xenoliths yielding conodont microfossils were entrained by the kimberlites. These xenoliths suggest that Upper Ordovician and Lower Silurian strata with a total thickness about 270–305 m were present on the Hall Peninsula at least until Early Cretaceous time (Zhang and Pell, 2013; 2014). Figure 1 A). Simplified geologic map of the Foxe Basin and vicinity (modified from Wheeler et al., 1997), showing the location of the Chidliak project area (red polygon), the drill hole CHI-482-10-DD01 with the black shale xenolith (red star), suspect natural hydrocarbon seep (yellow dots; location data from Budkewitsch et al., 2013) and Paleozoic (black cross) and Mesozoic (red cross) cores collected by shallow drillings during 1970s and 1980s (location data from Zhang, 2013a). B). Enlargement of the area enclosed by black rectangle in (A). Cumberland Sound, to the northeast, is partially underlain by Cretaceous clastic and Paleozoic carbonate sedimentary rocks (Fig. 1; MacLean et al., 1986). On the sea surface of Cumberland Sound, 28 suspect natural hydrocarbon seep occurrences were identified (Fig. 1; Budkewitsch et al., 2013), indicating an active petroleum system may occur in the sound; however, the source rocks remain uncertain. A rare black shale xenolith (Fig. 2A) was discovered from a kimberlite on the Hall Peninsula. Given the geologic and geographic position of the peninsula, it provides valuable evidence about the possible existence of an active …

Petroleum Prospects of Lamu Basin, South-Eastern Kenya

Abstract: The hydrocarbon potential of the sub-surface Lamu basin (SE Kenya) offshore sedimentary rock sequences of Mesozoic age formed the premise of this study. Major similarities and some differences in structural styles can be seen between the offshore Lamu and the Gondwana basins along the margins of Indian Ocean and Carnarvon basin along Australia’s North West Shelf, where oil pools have been discovered. The existing well results and recent 2-D seismic data have been interpreted to identify various structural styles and play fairway segments, which bolster the possibility that the Karroo to late Tertiary sedimentary mega-sequences (∼3000 – 13000 m thick), suitable for hydrocarbon exploration, could be visualized in both the onshore and offshore Lamu basin areas. Similarly, major reservoir-seal and potential source intervals have been identified in the present study. The hydrocarbon indicator from the well-log data shows that oil potential in complex multiple petroleum systems, ranging in age from Triassic to Tertiary, have tested gas deposits. Well control of only one exploratory well per 25,000 sq km in the offshore Lamu basin shows evidence of the existence of at least two active petroleum systems. The Lamu basin has evolved consequent to a complex tectonic activity related to continental rifting and block faulting of the Lamu-Anza and Central African rift systems. An attempt has been made to recommend the probable prognostic structural leads, which are controlled by NW-SE trending faults sympathetic to the Anza-Lamu rift systems, for future essential sub-surface features of source rocks, reservoir rocks and the cap rocks in the Lamu basin.

Understanding potential pressure regimes in undrilled Labrador deep water by use of global analogues

In recent years, new deepwater seismic-based exploration work has resulted in the revision of existing basin boundaries and identification of new, potentially oil-bearing basins in the deepwater Labrador region. The petroleum potential in this deepwater area has also been encouraged by the identification of slick and seepage locations using 2D seismic data and satellite imagery. The importance is that surface slicks possibly are related to subsurface hydrocarbon migration. Thus, all recent data collated together show strong evidence for an active petroleum system in deep water. Many of the wells in shallow water have been drilled with low mud weights, suggestive of low pore pressures. However, where thick shale packages are present, significant overpressure is observed by significant kicks. Clearly, there is a close association between thick (and deep) shale packages and high pore pressure. Thus, one of the key risks in developing the deepwater potential is to understand the pressure regime. The success of this approach has been highlighted recently by successful discoveries such as the presalt Lulu field onshore Brazil and associated discoveries in Gabon and Angola and postsalt discoveries that include Jubilee field offshore Ghana and the associated discovery of Zaedyus field in French Guiana. The deepwater Vøring Basin of the Mid-Norway North Sea and the Labrador slope and deep water share a similar passive margin setting to each other, similar facies associations, and structural development.

A basin modeling and organic geochemistry study in the Vallecitos syncline, San Joaquin Basin, California

The Vallecitos syncline is a westerly structural extension of the San Joaquin Basin. The Vallecitos oil field, comprised of eight separate areas that produce from Cretaceous and Paleogene reservoirs, accounted for 5.4 MMB of oil and 5.6 BCF associated of gas through 2010. However, exploration for oil and gas in the Vallecitos area is challenging due to structural complexity and limited data. The purpose of this study is to evaluate whether source rocks are actively generating petroleum in the Vallecitos syncline and to improve our understanding of burial history and timing of hydrocarbon generation. We conducted biomarker analysis on twenty-two oil samples from the Vallecitos syncline. Source-related biomarkers show two genetic groups of oil, which originated from two different source rocks. These results differ from earlier published interpretations in which the Kreyenhagen Formation is the only source rock in the Vallecitos syncline, and suggest that the Cretaceous Moreno Formation in the syncline also is an active source rock.Stratigraphic evidence and modeling suggest that late Cenozoic episodes of erosion due to folding and uplift removed significant overburden on the flanks of the syncline. To better understand the petroleum systems and clarify the total active source rocks in the area, 2D burial histories were generated through the Vallecitos syncline. A published cross-section through the deepest part of the syncline was selected to conduct thermal history, basin evolution, and migration analyses. The 2D model results indicate that the lower Kreyenhagen Formation has various maturities within the formation at different locations in the present-day syncline. The basal part of the Kreyenhagen Formation is in the dry gas window and maturity decreases away from the central part to the flanks. It remains immature along shallow portions of the present-day flanks. In contrast, the basal part of the Moreno Formation achieved extremely high maturity (past the gas generation zone) but is in the oil generation zone on the flanks of the syncline at shallow depth. All of our geochemical and 2D model results suggest that there are two active source rocks in the Vallecitos syncline. Accordingly, we propose that there are two active petroleum systems in the Vallecitos syncline.

Tracing the origin of thermogenic hydrocarbon signals in pockmarks from the southwestern Barents Sea

The glacially influenced southwestern Barents Sea is a promising area for petroleum exploration. The present study area, which is located in the Loppa High region, exhibits extensive pockmark fields covering an area of several square kilometers and containing thousands of pockmarks in high density. To investigate whether the pockmark formation was driven by petroleum leakage to the surface, acting thus as indicators for an active petroleum system, gravity cores from selected pockmark and reference sites were investigated using an organic geochemical approach. Various biomarkers indicative of thermogenic hydrocarbons such as short chain n-alkanes with a low carbon preference index, alkylcyclohexanes, αβ-hopanes, steranes and diasteranes mixed with biomarkers representing immature organic matter were detected in the pockmark, but also in reference cores outside of the pockmark and even from a non-pockmark area. The abundance and level of thermal maturity of the thermogenic hydrocarbons are comparable between the pockmark and reference sites. Additionally, their distribution with depth is quite similar to those of the immature biomarkers. These observations support the conclusion that the thermogenic hydrocarbon signal in the pockmarks is the result of reworked, eroded mature material mixed with immature organic matter distributed across the entire area, rather than the result of seepage events of thermogenic hydrocarbons through the pockmark system. The data show that in the Loppa High region the pure presence of petroleum-derived hydrocarbons in pockmark areas cannot be used to indicate the presence or leakage of deeper petroleum systems.

Organic geochemistry and petrography of Lower Cretaceous Wealden black shales of the Lower Saxony Basin: The transition from lacustrine oil shales to gas shales

Ninety-seven Wealden black shale samples from three wells in the Lower Saxony Basin have been studied by organic geochemical and organic petrographical methods to determine their maturity, organic facies and depositional environment. The maturities of the three wells range from early mature (Ex-A), late to postmature (Ex-C) to overmature (Ex-B) as determined by vitrinite reflectance measurements, diamondoid ratios and other geochemical maturity parameters. Ex-C and Ex-B show distinct petrographic features related to oil generation and migration. In particular, the occurrence of dispersed solid bitumen replacing initial type I kerogen suggests a formerly active petroleum system. Structural and textural differences between early mature alginites and solid bitumen in postmature to overmature samples show an alteration of the pore system with increasing maturity. A freshwater depositional environment is indicated by widespread occurrence of botryococcus algae and other small alginite particles predominating in the immature well. These alginites are absent in the more mature gas shales of wells Ex-C and Ex-B. Geochemical evidence of algae and phytoplankton in general is provided by numerous biomarker parameters, while the occurrence of β-carotane in some samples indicates events of increased salinity, although no hypersaline conditions are inferred due to very low gammacerane indices. Increased amounts of vitrinite and inertinite in samples of Ex-B suggest locally significant terrigenous input of organic matter for some periods during Wealden Shale deposition. High sulfur/organic carbon ratios provide evidence for sulfate rich waters and (partly) anoxic bottom water conditions. While the lower mature lacustrine source rocks generate paraffinic/waxy oils, gas and condensates are produced at post-mature stages. Furthermore, maturity distribution maps from 3D numerical petroleum systems modeling reveal substantial differences in respect to petroleum generation.

New exploration opportunities in the offshore Houtman and Abrolhos sub-basins, northern Perth Basin, WA

The 2013 Acreage Release Areas W13-19 and W13-20 in the offshore northern Perth Basin, Western Australia, cover more than 19,000 km2 in parts of the Houtman, Abrolhos, Zeewyck and Gascoyne sub-basins. The Release Areas are located adjacent to WA-481-P, the only active offshore exploration permit in the Perth Basin, granted to joint venture partners Murphy Australia Oil Pty Ltd, Kufpec Australia Pty Ltd and Samsung Oil and Gas Australia Pty Ltd in August 2012. Geoscience Australia recently undertook a regional prospectivity study in the area as part of the Australian Government’s Offshore Energy Security Program, which provides fresh insights into basin evolution and hydrocarbon prospectivity. A sequence stratigraphic framework, based on new biostratigraphic sampling and interpretation, and an updated tectonostratigraphic model, using multiple 1D burial history models for Permian to Cenozoic sequences, have been developed. New geochemical studies of key offshore wells demonstrate that the oil-prone source interval of the Lopingian–Lower Triassic Hovea Member extends regionally offshore into the Abrolhos Sub-basin and potentially as far as the Houtman Sub-basin. This is supported by fluid inclusion data that provide evidence for palaeo-oil columns within Permian reservoirs in wells from the Abrolhos Sub-basin. Oil trapped in fluid inclusions in Houtman-1 can be linked to Jurassic source rocks, suggesting that multiple petroleum systems are effective in the Release Areas. The presence of active petroleum systems is also supported by the results of a recent marine survey. Potential seepage sites on the seafloor over reactivated faults correlate with hydroacoustic flares, pockmarks and dark colored viscous fluids that were observed over the areas. This may indicate an active modern-day petroleum system in the Houtman Sub-basin. Finally, a trap integrity analysis was undertaken to mitigate exploration risks associated with trap failure during Early Cretaceous breakup and provides a predictive approach to prospect assessment. These results provide strong support for the presence of active petroleum systems in the offshore northern Perth Basin and upgrade the prospectivity of the Release Areas.

Distribution of hydrocarbon leakage indicators in the Malvinas Basin, offshore Argentine continental margin

Abstract The Malvinas Basin is located in the southernmost Argentinian continental margin. Despite the lack of commercial hydrocarbon accumulation discoveries, the presence of thermogenic gas in gravity cores and seafloor oil slicks points to the existence of an active petroleum system in this basin. Based on the analysis of over 1000 2D industrial seismic-reflection profiles, covering the shelf and upper-slope of the Malvinas Basin offshore the southernmost Argentinian margin, we document the presence of buried and present-day features including subsurface seismic chimneys, seabed and buried pockmarks, and buried-mounded structures which are probably indicators of long-term leakage history of both liquid and gaseous hydrocarbons since the Eocene to the Present. Based on their distribution and likely controlling factors, these leakage features were classified into four areas of leakage: area I to area IV. Area I is located in the centre of the basin and contains seismic anomalies as pipes originating above or in a polygonal faulted Pliocene–Miocene interval accompanied by bright spots and seabed pockmarks. Area IIa/b is located in the south of the basin and contains pipes and buried pockmarks located close to the southern transpressional deformation front. Area III is located to the east of the basin and consists of pipes hosted in a Mid-Cretaceous deltaic-fan. Area IV, located in the western part of the basin, consists of buried Eocene mounded structures located near the Rio Chico High and above basement highs and faults. They are interpreted as authigenic carbonate mounds possibly derived from oxidation of thermogenic methane that leaked upwards along basement-rooted faults. A reversed-polarity seismic reflection showing a lineation of bright spots has been identified at an average depth of 170 m below seafloor in water depths of about 500 m. We interpret this reflection as a bottom simulating reflector (BSR), which enables us to estimate a geothermal gradient of 23.9 ± 2.0 °C/km for the area. Near and above the thrust faults of a transpressional deformation front, the vertical pipes in area II cross-cut possible hydrate deposits, suggesting that there is a current breaching of these deposits due to tectonically-driven upward focused fluid flow and heat transport. The gas source for the features observed in areas I, IIa/b and IV is most likely leakage from the uppermost Jurassic–Barremian reservoir Springhill Fm., although a biogenic gas source for leakage indicators in area I cannot be ruled out. The leakage indicators in area III are possibly sourced from the Mid-Cretaceous sediments of the Middle Inoceramus Fm.

Tectonic evolution and hydrocarbon potential of the Aptian series in the Mahdia offshore area, Tunisia

The present study was initiated with the aim to highlight the remaining hydrocarbon potential of the Mahdia area and to guide the future exploration activities.This study was based on subsurface data. Seismic mapping shows that the area is dominated by series of NW-SE horst and grabens. This present day structural configuration is the result of multiple tectonic events which affected the study area from Cretaceous to Quaternary.The active petroleum system of the Mahdia area was proved by the oil discovery of the Mahdia-1 well. The Allam and Aptian carbonates are the main considered reservoirs in the region; the Albian Fahdene formation represents the main source rock of these Aptian carbonates and the overlaying upper Fahdene shale and marls provide their effective top seal.The Mahdia-1 structure appears as a faulted anticline. The migration pathways could be either throw fault plans and/or throughout major unconformities. During Cretaceous to Early Paleogene, the Mahdia offshore area was affected by series of volcanic activities. This volcanism has increased significantly the geothermal gradient and accelerated the source rock maturity.Within the Mahdia area, several prospects and leads remain undrilled and could replenish the operators' portfolio.

New data on the Vrancea Nappe (Moldavidian Basin, Outer Carpathian Domain, Romania): paleogeographic and geodynamic reconstructions

A study has been performed on the Cretaceous to Early Miocene succession of the Vrancea Nappe (Outer Carpathians, Romania), based on field reconstruction of the stratigraphic record, mineralogical-petrographic and geochemical analyses. Extra-basinal clastic supply and intra-basinal autochthonous deposits have been differentiated, appearing laterally inter-fingered and/or interbedded. The main clastic petrofacies consist of calcarenites, sub-litharenites, quartzarenites, sub-arkoses, and polygenic conglomerates derived from extra-basinal margins. An alternate internal and external provenance of the different supplies is the result of the paleogeographic re-organization of the basin/margins system due to tectonic activation and exhumation of rising areas. The intra-basinal deposits consist of black shales and siliceous sediments (silexites and cherty beds), evidencing major environmental changes in the Moldavidian Basin. Organic-matter-rich black shales were deposited during anoxic episodes related to sediment starvation and high nutrient influx due to paleogeographic isolation of the basin caused by plate drifting. The black shales display relatively high contents in sub-mature to mature, Type II lipidic organic matter (good oil and gas-prone source rocks) constituting a potentially active petroleum system. The intra-basinal siliceous sediments are related to oxic pelagic or hemipelagic environments under tectonic quiescence conditions although its increase in the Oligocene part of the succession can be correlated with volcanic supplies. The integration of all the data in the “progressive reorientation of convergence direction” Carpathian model, and their consideration in the framework of a foreland basin, led to propose some constrains on the paleogeographic-geodynamic evolutionary model of the Moldavidian Basin from the Late Cretaceous to the Burdigalian.

Stratigraphic update of the Cenozoic Sub-Numidian formations of the Tunisian Tell (North Africa): Tectonic/sedimentary evolution and correlations along the Maghrebian Chain

The Sub-Numidian Tertiary stratigraphic record of the Tunisian Tell has been updated by means of 11 stratigraphic successions belonging to the Maghrebian Flysch Basin (N-African Margin) reconstructed in the Tunisian Numidian Zone and the Triassic Dome Zone. The Sub-Numidian successions studied range from the Paleocene to the Priabonian, representing a major change in the sedimentation from the latest Cretaceous onwards. The Sub-Numidian succession and the Numidian Formation are separated by an Intermediate interval located between two erosive surfaces (local paraconformities). The stratigraphic analysis has revealed diachronous contacts between distal slope to basinal sedimentary formation, allowing the identification of an Early Eocene Chouabine marker bed. The integrated biostratigraphic analysis made by means of planktonic foraminifera and calcareous nannoplankton updates the ages of the formations studied, proving younger than previously thought. The new definition of the Sub-Numidian stratigraphy enables a better correlation with equivalent successions widely outcropping along the Maghrebian, Betic, and southern Apennine Chains. The study proposes a new evolutionary tectonic/sedimentary model for this Tunisian sector of the Maghrebian Chain during the Paleogene after the Triassic–Cretaceous extensional regime. This paleogeographic reorganization is considered a consequence of the beginning of the tectonic inversion (from extensional to compressional), leading to the end of the preorogenic sedimentation. Our results suggest a non-tabular stratigraphy (marked by lateral changes of lithofacies, variable thicknesses, and the presence of diachronous boundaries) providing significant elements for a re-evaluation of active petroleum systems on the quality, volume, distribution, timing of oil generation, and on the migration and accumulation of the oil.

Diagenesis of Paleozoic playa-lake and ephemeral-stream deposits from the Pimenta Bueno Formation, Siluro–Devonian (?) of the Parecis Basin, central Brazil

The Parecis Basin is a large intracratonic rift located in central Brazil and filled with Paleozoic carbonate, evaporite and siliciclastic sediments. The occurrence of gas seeps has recently attracted significant exploration interest by the Brazilian petroleum agency and by Petrobras. The continuously cored PB-01-RO well provided the first opportunity to study the depositional environments, diagenetic evolution and hydrocarbon potential of the largely unknown sedimentary successions of the Parecis Basin. The cored lithologies, belonging to the Siluro–Devonian (?) Pimenta Bueno Formation, are interpreted as deposited in playa-lake and ephemeral-stream environments. The deposits display a strong facies control on the diagenetic mineral assemblages and evolution. Diagenetic minerals in the ephemeral-stream deposits include eogenetic hematite and smectitic clay coats and quartz cement, and the mesogenetic process includes precipitation of sulfates (anhydrite and barite) and carbonates (calcite, dolomite and kutnahorite–ankerite–huntite), followed by partial dissolution of these carbonates and sulfates, and of feldspar grains. Telogenetic processes include the precipitation of hematite and kaolinite within secondary pores, and the replacement of anhydrite by gypsum. A second burial phase and mesodiagenesis is indicated by the precipitation of discrete K-feldspar crystals within moldic pores after dissolved feldspars, and by the illitization of etched, telogenetic kaolinite. The playa-lake deposits show early diagenetic dolomitization of lime mud, precipitation of anhydrite nodules and extensive silicification. The anhydrite nodules were replaced by gypsum and chalcedony during telodiagenesis. Potential source rocks are locally represented by organic shales. The fluvial sandstones show fair reservoir quality and limited compaction, as indicated by their intergranular volume, suggesting that the succession has undergone moderate burial. Potential seals for hydrocarbon accumulations are provided by the evaporites and playa-lake mudstones. The presence of an active petroleum system in the basin, as indicated by the gas seeps, suggests a good hydrocarbon exploration potential for the Parecis Basin, gas and stresses the importance of studying the depositional and diagenetic evolution of its sedimentary successions.

Hydrocarbon charge in the onshore Canning Basin: insights from quantitative fluorescence and fluid inclusion investigations

The vast and mostly onshore Canning Basin—with an area of approximately 595,000 m2—is the least explored onshore sedimentary basin in Australia. As part of the petroleum system assessment carried out by WA DMP, more than 160 samples were investigated from eight wells in the onshore Canning Basin—they are: Acacia-1 Dodonea-1 Dodonea-2 Lake Hevern-1 Looma-1 White Hill-1 Wilson Cliffs-1 Yulleroo-1. Fluid inclusion and quantitative fluorescence techniques developed by CSIRO were used, including: The grains containing oil inclusions (GOITM) technique; The quantitative grain fluorescence (QGF) technique; QGF on extracts (QGF-E); and, the total scanning fluorescence (TSF) technique. The results reveal a widespread occurrence of hydrocarbon shows in the reservoir intervals investigated—7–8 wells showed evidence of oil migration and/or accumulations often occurring at multiple depth intervals. In White Hill-1, elevated QGF and QGF-E responses were recorded in the sandy units in a depth interval of more than 500 m in the Fairfield Group. A residual or palaeo oil column of &gt;20 m gross height at 1,655 m was apparent from the QGF and QGF-E depth profiles—and GOI and TSF data. Oil inclusions from the Fairfield Group in White Hill-1 show spectral signature typical of thermally mature and light-medium API gravity. The TSF results also indicate the presence of some condensate species, as well as relatively heavy and possibly bio-degraded oils. The new fluid inclusion and fluorescence data provide direct evidence of an active petroleum system in the Canning Basin at multiple reservoir intervals, which may be of local significant quantity.

Chapter 34 Geology and petroleum potential of the rifted margins of the Canada Basin

Abstract Three sides of the Canada Basin are bordered by high-standing, conjugate rift shoulders of the Chukchi Borderland, Alaska and Canada. The Alaska and Canada margins are mantled with thick, growth-faulted sediment prisms, and the Chukchi Borderland contains only a thin veneer of sediment. The rift-margin strata of Alaska and Canada reflect the tectonics and sediment dispersal systems of adjacent continental regions whereas the Chukchi Borderland was tectonically isolated from these sediment dispersal systems. Along the eastern Alaska–southern Canada margin, termed herein the ‘Canning–Mackenzie deformed margin’, the rifted margin is deformed by ongoing Brooks Range tectonism. Additional contractional structures occur in a gravity fold belt that may be present along the entire Alaska and Canada margins of the Canada Basin. Source-rock data inboard of the rift shoulders and regional palaeogeographic reconstructions suggest three potential source-rock intervals: Lower Cretaceous (Hauterivian–Albian), Upper Cretaceous (mostly Turonian) and Lower Palaeogene. Burial history modelling indicates favourable timing for generation from all three intervals beneath the Alaska and Canada passive margins, and an active petroleum system has been documented in the Canning–Mackenzie deformed margin. Assessment of undiscovered petroleum resources indicates the greatest potential in the Canning–Mackenzie deformed margin and significant potential in the Canada and Alaska passive margins.