BURIAL,TEMPERATURE AND MATURATION HISTORY OF THE AUSTRAL AND WESTERN MALVINAS BASINS,SOUTHERN ARGENTINA,BASED ON 3D BASIN MODELLING

This paper presents a numerical petroleum systems model for the Jurassic‐Tertiary Austral (Magallanes) Basin, southern Argentina, incorporating the western part of the nearby Malvinas Basin. The modelling is based on a recently published seismo‐stratigraphic interpretation and resulting depth and thickness maps. Measured vitrinite reflectance data from 25 wells in the Austral and Malvinas Basins were used for thermal model calibration; eight calibration data sets are presented for the Austral Basin and four for the Malvinas Basin. Burial history reconstruction allowed eroded thicknesses to be estimated and palaeo heat‐flow values to be determined. Six modelled burial, temperature and maturation histories are shown for well locations in the onshore Austral Basin and the western Malvinas Basin. These modelled histories, combined with kinetic data measured for a sample from the Lower Cretaceous Springhill Formation, were used to model hydrocarbon generation in the study area. Maps of thermal maturity and transformation ratio for the three main source rocks (the Springhill, Inoceramus and Lower Margas Verdes Formations) were compiled. The modelling results suggest that deepest burial occurred during the Miocene followed by a phase of uplift and erosion. However, an Eocene phase of deep burial leading to maximum temperatures cannot be excluded based on vitrinite reflectance and numerical modelling results. Relatively little post‐Miocene uplift and erosion (approx. 50–100 m) occurred in the Malvinas Basin. Based on the burial‐ and thermal histories, initial hydrocarbon generation is interpreted to have taken place in the Early Cretaceous in the Austral Basin and to have continued until the Miocene. A similar pattern is predicted for the western Malvinas Basin, with an early phase of hydrocarbon generation during the Late Cretaceous and a later phase during the Miocene. However, source rock maturity (as well as the transformation ratio) remained low in the Malvinas Basin, only just reaching the oil window. Higher maturities are modelled for the deeper parts of the Austral Basin, where greater subsidence and deeper burial occurred.     

BIOMARKER CHARACTERISTICS OF POTENTIAL SOURCE ROCKS IN THE JABAL NAFUSAH AREA,NW LIBYA: PETROLEUM SYSTEMS SIGNIFICANCE

The Jifarah Arch of NW Libya is a structurally prominent feature at the eastern end of the regional Talemzane Arch, separating the Ghadamis hydrocarbon province to the south from the offshore Pelagian province to the north. The Arch has experienced a complex structural history with repeated episodes of uplift, exhumation and burial. This paper provides a provisional assessment of its hydrocarbon habitat based on detailed geochemical analyses of potential Triassic, Silurian and Ordovician source rocks encountered by wells drilled in the area. Twenty‐seven core and cuttings samples of marine shales were collected from eight widely‐ dispersed wells and analyzed using standard Rock‐Eval pyrolysis techniques. Kerogen types II‐III were identified in the majority of Triassic samples analysed, indicating a low hydrocarbon generation potential, but oil‐prone Type II kerogen was found in the basal Silurian Tanezzuft Formation and Ordovician Memouniat Formation. The presence of steranes and acyclic isoprenoids suggested variable inputs of algal, bacterial and terrestrial organic matter, while biomarkers including C₃₀‐gammacerane and β–carotene and selected biomarker ratios (Pr/Ph ratio and homohopane index) were used to assess their depositional environment. Results indicate that extended zones with periodic (if not continuous) oxygen‐deficient conditions existed throughout the basin during Late Ordovician and Early Silurian time, favouring the preservation of organic matter. The thermal maturity of the samples was assessed by Rock‐Eval pyrolysis, zooclast reflectance, molecular ratios including C_32‐22S/(22S+22R)‐homohopanes, Ts/(Ts+Tm), C₂₉‐steranes and parameters based on the relative abundance of methylphenanthrene, methyldibenzothiophene and methylnaphthalene isomers. The results indicate significant variability in thermal maturity, with Ordovician and Silurian source rocks ranging from 0.6% to 0.7% VR_o equivalent increasing to 1.0% locally. These values represent palaeo‐maturities achieved at different times in the past and are considered too low to have generated significant volumes of hydrocarbons directly. However the downdip equivalents of these source rocks in the adjacent Ghadamis Basin contributed to prolific petroleum systems. The absence of large petroleum accumulations on the Jifarah Arch contrasts with the western part of the geologically similar Talemzane Arch, which harbours several giant and supergiant oil and gas fields. This difference is attributed both to the complex structural history of the Jifarah Arch, which permitted post‐charge leakage of palaeo‐accumulations, and stratigraphic migration barriers which restricted migration between Tanezzuft source rocks and Ordovician and Triassic reservoirs.     

ORGANIC AND INORGANIC GEOCHEMICAL AND MINERALOGICAL ASSESSMENTS OF THE SILURIAN AKKAS FORMATION,WESTERN IRAQ

The Silurian Akkas Formation has been reported and described only in the subsurface of western Iraq. The formation is divided into the lower Hoseiba Member, which contains two high‐TOC “hot” shale intervals that together are around 60 m thick, and the overlying Qaim Member that is composed of lower‐TOC “cold” shales. This study investigates the source rock potential of Akkas Formation shales from the Akkas‐1and Akkas‐3 wells in western Iraq and assesses the relationship between their mineral and elemental contents and their redox depositional conditions and thermal maturity. Twenty‐six shale samples from both members of the Akkas Formation from the Akkas‐1and Akkas‐3 wells were analysed. The results showed that the upper, ~20 m thick“hot” shale interval in the lower Hoseiba Member has good source rock characteristics with an average TOC content of 5.5 wt% and a mean Rock‐Eval S₂ of 10 kg/tonne. Taken together, the two “hot” shale intervals and the intervening “cold” shale of the Hoseiba Member are ~125‐150 m thick and have an average TOC of 3.3 wt% and mean S₂ of 6.2 kg/tonne. The samples from the Hoseiba Member contain mixed Type II / III or Type III kerogen with an HI of up to 296 mgS₂/gTOC. Visual organic‐matter analysis showed that the samples contain dark brown, opaque amorphous organic matter with minor amounts of vitrinite‐like and algal (Tasmanites) material. Pyrolysis – gas chromatography undertaken on a single sample indicated a mature (or higher) algal‐dominated Type II kerogen. High spore and acritarch colour index values and weak or absent fluorescence similarly suggest that the lower part of the Akkas Formation is late mature to early post‐mature for oil generation. “Cold” shales from the Qaim Member in the Akkas‐3 well may locally have good source rock potential, while samples from the upper part of the Qaim Member from the Akkas‐1 well have little source rock potential. Varied results from this interval may reflect source rock heterogeneity and limited sample coverage. Mineralogically, all the shale samples studied were dominated by clay minerals – illite and kaolinite with minor amounts of chlorite and illite mixed layers. Non‐clay minerals included quartz, carbonates, feldspars and pyrite along with rare apatite and anatase. Palaeoredox proxies confirmed the general link between anoxia and “hot” shale deposition; however, there was no clear relationship between TOC and U suggesting that another carrier of U could be present. Rare Earth Element (REE) contents suggested a slight change in sediment provenance during the deposition of the Akkas Formation. The presence of common micropores and fractures identified under SEM indicates that these shales could become potential unconventional reservoirs following hydraulic fracturing. Evidence for the dissolution of carbonate minerals was present along fractures, suggesting the possible passage of diagenetic fluids. Palynological analysis combined with existing graptolite studies support a Wenlock ‐ Pridoli/Ludlow age for the Akkas “hot”shales. This is younger than many other regional “hot shale” age estimates and warrants further detailed investigation.     

ORGANIC GEOCHEMISTRY,BURIAL HISTORY AND HYDROCARBON GENERATION MODELLING OF THE UPPER JURASSIC MADBI FORMATION,MASILA BASIN,YEMEN

The Masila Basin is an important hydrocarbon province in Yemen but the origin of its hydrocarbons is not fully understood. In this study, we evaluate Upper Jurassic source rocks in the Madbi Formation and assess the results of basin modelling in order to improve our understanding of burial history and hydrocarbon generation. This source rock has generated commercial volumes of hydrocarbons which migrated into Jurassic and Lower Cretaceous reservoir rocks. Cuttings samples of shales from the Upper Jurassic Madbi Formation from boreholes in the centre-west of the Masila Basin were analysed using organic geochemistry (Rock-Eval pyrolysis, extract analysis) and organic petrology. The shales generally contain more than 2.0 wt % TOC and have very good to excellent hydrocarbon potential. Kerogen is predominantly algal Type II with minor Type I. Thermal maturity of the organic matter is R_r 0.69–0.91%. Thermal and burial history models indicate that the Madbi Formation source rock entered the early-mature to mature stage in the Late Cretaceous to Early Tertiary. Hydrocarbon generation began in the Late Cretaceous, reaching maximum rates during the Early Tertiary. Cretaceous subsidence had only a minor influence on source rock maturation and OM transformation.     

BURIAL HISTORY AND THERMAL MATURITY EVOLUTION OF THE TERMIT BASIN,NIGER

Reconstruction of the burial history and thermal evolution of the Cretaceous – Tertiary Termit Basin, a sub‐basin within the larger Eastern Niger Basin of Niger, indicates spatially and temporally variable conditions for organic matter maturation during the basin's multi‐phased evolution. Three episodes of tectonic subsidence which correspond to the observed fault mechanical stratigraphy within the Termit Basin are identified: Late Cretaceous, Maastrichtian to early Paleocene, and Oligocene. These episodes fall within the regional tectonic phases of the West African Rift System delineated by previous studies. The basin exhibits substantial heterogeneity in the magnitude of the tectonic episodes and in consequent thermal maturities. For this paper, 1D burial and thermal histories of eight widely dispersed wells in the Agadem permit area in the SW of the Termit Graben were modelled to investigate the maturation of organic matter in source rocks ranging from Santonian to Oligocene in age. The kinetic modelled maturities match with maturities based on Rock‐Eval T_max values for four wells if present‐day heat flows are elevated. Future exploration strategies in the Termit Basin should take into consideration these heterogeneities in thermal histories and tectonic pulses, which may lead to the development of hydrocarbon accumulations with different oil‐gas compositions in different reservoir compartments.     

BURIAL,TEMPERATURE AND MATURATION HISTORY OF CRETACEOUS SOURCE ROCKS IN THE NW PERSIAN GULF,OFFSHORE SW IRAN: 3D BASIN MODELLING

This study presents a 3D numerical model of a study area in the NW part of the Persian Gulf, offshore SW Iran. The purpose is to investigate the burial and thermal history of the region from the Cretaceous to the present day, and to investigate the location of hydrocarbon generating kitchens and the relative timing of hydrocarbon generation/migration versus trap formation. The study area covers about 20,000 km² and incorporates part of the intra‐shelf Garau‐Gotnia Basin and the adjacent Surmeh‐Hith carbonate platform. A conceptual model was developed based on the interpretation of 2700 km of 2D seismic lines, and depth and thickness maps were created tied to data from 20 wells. The thermal model was calibrated using bottom‐hole temperature and vitrinite reflectance data from ten wells, taking into account the main phases of erosion/non‐deposition and the variable temporal and spatial heat flow histories. Estimates of eroded thicknesses and the determination of heat‐flow values were performed by burial and thermal history reconstruction at various well and pseudo‐well locations. Burial, temperature and maturation histories are presented for four of these locations. Detailed modelling results for Neocomian and Albian source rock successions are provided for six locations in the intra‐shelf basin and the adjacent carbonate platform. Changes in sediment supply and depocentre migration through time were analyzed based on isopach maps representing four stratigraphic intervals between the Tithonian and the Recent. Backstripping at various locations indicates variable tectonic subsidence and emergence at different time periods. The modelling results suggest that the convergence between the Eurasian and Arabian Plates which resulted in the Zagros orogeny has significantly influenced the burial and thermal evolution of the region. Burial depths are greatest in the study area in the Binak Trough and Northern Depression. These depocentres host the main kitchen areas for hydrocarbon generation, and the organic‐rich Neocomian and Albian source rock successions have been buried sufficiently deeply to be thermally mature. Early oil window maturities for these successions were reached between the Late Cretaceous (90 Ma) and the early Miocene (18 Ma) at different locations, and hydrocarbon generation may continue at the present‐day.     

BIOMARKER CHARACTERISTICS OF CRUDE OILS FROM THE MURZUQ BASIN,SW LIBYA

Twenty crude oil samples from the Murzuq Basin, SW Libya (A‐, R‐ and I‐Fields in Blocks NC115 and NC186) have been investigated by a variety of organic geochemical methods. Based on biomarker distributions (e.g. n‐alkanes, isoprenoids, terpanes and steranes), the source of the oils is interpreted to be composed of mixed marine/terrigenous organic matter. The values of the Pr/Ph ratio (1.36–2.1), C₃₀‐diahopane / C₂₉ Ts ratio and diasterane / sterane ratio, together with the low values of the C₂₉/ C₃₀‐hopane ratio and the cross‐plot of the dibenzothiophene/phenanthrene ratio (DBT/P) versus Pr/Ph ratio in most of oil samples, suggest that the oils were sourced from marine clay‐rich sediments deposited in mild anoxic depositional environments. Assessment of thermal maturity based on phenanthrenes, aromatic steroids (e.g. monoaromatic (MA) and triaromatic (TA) steroid hydrocarbons), together with terpanes, and diasterane/sterane ratios, indicates that crude oils from A‐Field are at high levels of thermal maturity, while oils from Rand I‐Fields are at intermediate levels of thermal maturity. Based on the distributions of n‐alkanes and the absence of 25‐norhopanes in all of the crude oils analysed, none of the oils appear to have been biodegraded. Correlation of the crude oils points to a single genetic family and this is supported by the stable carbon isotope values. The oils can be divided into two sub‐families based on the differences in maturities, as shown in a Pr/nC₁₇ versus Ph/nC₁₈ cross‐plot. Sub‐family‐A is represented by the highly mature oils from A‐Field. Sub‐family‐B comprises the less mature oils from R‐ and I‐Fields. The two sub‐families may represent different source kitchens of different thermal maturity or different migration pathways. In summary, the geochemical characteristics of oil samples from A‐, R‐, and I‐Fields suggest that all the crude oils were generated from similar source rocks. Depositional environment conditions and advanced thermal maturities of these oils are consistent with previously published geochemical interpretations of the Rhuddanian “hot shale” in the Tanezzuft Formation, which is thought to be the main source rock in the Murzuq Basin.     

SHALE‐GAS POTENTIAL OF THE MID‐CARBONIFEROUS BOWLAND‐HODDER UNIT IN THE CLEVELAND BASIN (YORKSHIRE), CENTRAL BRITAIN

The shale‐gas potential of mid‐Carboniferous mudrocks in the Bowland‐Hodder unit in the Cleveland Basin (Yorkshire, northern England) was investigated through the analysis of a cored section from the uppermost part of the unit in the Malton‐4 well using a multidisciplinary approach. Black shales are interbedded with bioturbated and bedded sandstones, representing basinal‐offshore to prodelta – delta‐front lithofacies. The total organic carbon (TOC) content of the shales ranges from 0.37 to 2.45 wt %. Rock‐Eval pyrolysis data indicate that the organic matter is mainly composed of Type III kerogen with an admixture of Type II kerogen. T_max (436–454°C), 20S/(20S+20R) C₂₉ sterane ratios, and vitrinite reflectance values indicate that organic matter is in the mid‐ to late‐ mature (oil) stage with respect to hydrocarbon generation. Sedimentological and geochemical redox proxies suggest that the black shales were deposited in periodically oxic‐dysoxic and anoxic bottom waters with episodic oxic conditions, explaining the relatively low TOC values. The Rock‐Eval parameters indicate that the analysed mudrocks have a limited shale‐gas potential. However, burial and thermal history modelling, and VR_r data from other wells in the region, indicate that where they are more deeply‐buried, the Bowland‐Hodder shales will be within the gas window with VR_r > 1.1 % at depths in excess of 2000 m. Therefore although no direct evidence for a high shale‐gas potential in the Cleveland Basin has been found, this cannot be precluded at greater depths especially if deeper horizons are more organic rich.     

AN EVALUATION OF THE HYDROCARBON POTENTIAL OF THE SEDIMENTARY BASINS OF LIBYA

Distinctive structural and stratigraphic styles, together with the timely development of source rocks, reservoirs and seals, have produced in Libya the richest hydrocarbon habitats on the African continent. These habitats are located in the Sirte Basin (29,000 MM brl of proved reserves), and Ghadames Basins and Pelagian Shelf (3,000 MM brls of proved reserves). Significant oil discoveries have also been made in the Murzuk Basin (1,500 MM brl of proved reserves) and the offshore Cyrenaica Platform.
Four major potential source rocks have been identified in Libya: the Sirte shales (Campanian), the Hagfa shales (Palaeocene), the Tanezzuft shales (Silurian), and shales of Devonian age. The Sirte and Hagfa shales have generated hydrocarbons for most of the prolific reservoirs in the Sirte Basin. The Sirte shales supply hydrocarbons to clastic reservoirs of Cambro-Ordovician age (the Gargaf Group) and Lower Cretaceous age (Nubian sandstones), and also to Upper Cretaceous carbonates. The Hagfa shales source most of the Tertiary reservoirs in the Sirte Basin and possibly the Cyrenaica Platform. Silurian (Tanezzuft) and Devonian shales supply hydrocarbons to reservoirs of Palaeozoic and Mesozoic ages, particularly Silurian and Devonian sandstones in the Ghadames and Murzuk Basins, and the Cyrenaica Platform.
The principal seals in the Sirte Basin are Late Cretaceous and Tertiary shales and anhydrites. Palaeozoic and Mesozoic shales, impermeable carbonates, and occasional anhydrites form the major seals in the Ghadames and Murzuk Basins and the Cyrenaica Platform.     

HYDROCARBON GENERATION POTENTIAL AND DEPOSITIONAL ENVIRONMENT OF SHALES IN THE CRETACEOUS NAPO FORMATION,EASTERN ORIENTE BASIN,ECUADOR

Marine shale samples from the Cretaceous (Albian‐Campanian) Napo Formation (n = 26) from six wells in the eastern Oriente Basin of Ecuador were analysed to evaluate their organic geochemical characteristics and petroleum generation potential. Geochemical analyses included measurements of total organic carbon (TOC) content, Rock‐Eval pyrolysis, pyrolysis — gas chromatography (Py—GC), gas chromatography — mass‐spectrometry (GC—MS), biomarker distributions and kerogen analysis by optical microscopy. Hydrocarbon accumulations in the eastern Oriente Basin are attributable to a single petroleum system, and oil and gas generated by Upper Cretaceous source rocks is trapped in reservoirs ranging in age from Early Cretaceous to Eocene. The shale samples analysed for this study came from the upper part of the Napo Formation T member (“Upper T”), the overlying B limestone, and the lower part of the U member (“Lower U”).The samples are rich in amorphous organic matter with TOC contents in the range 0.71–5.97 wt% and Rock‐Eval T_max values of 427–446°C. Kerogen in the B Limestone shales is oil‐prone Type II with δ¹³C of ?27.19 to ?27.45‰; whereas the Upper T and Lower U member samples contain Type II–III kerogen mixed with Type III (δ¹³C > ?26.30‰). The hydrocarbon yield (S₂) ranges from 0.68 to 40.92 mg HC/g rock (average: 12.61 mg HC/g rock). Hydrogen index (HI) values are 427–693 mg HC/g TOC for the B limestone samples, and 68–448 mg HC/g TOC for the Lower U and Upper T samples. The mean vitrinite reflectance is 0.56–0.79% R₀ for the B limestone samples and 0.40–0.60% R₀ for the Lower U and Upper T samples, indicating early to mid oil window maturity for the former and immature to early maturity for the latter. Microscopy shows that the shales studied contain abundant organic matter which is mainly amorphous or alginite of marine origin. Extracts of shale samples from the B limestone are characterized by low to medium molecular weight compounds (n‐C₁₄ to n‐C₂₀) and have a low Pr/Ph ratio (≈ 1.0), high phytane/n‐C₁₈ ratio (1.01–1.29), and dominant C₂₇ regular steranes. These biomarker parameters and the abundant amorphous organic matter indicate that the organic matter was derived from marine algal material and was deposited under anoxic conditions. By contrast, the extracts from the Lower U and Upper T shales contain medium to high molecular weight compounds (n‐C₂₅ to n‐C₃₁) and have a high Pr/ Ph ratio (>3.0), low phytane/n‐C₁₈ ratio (0.45–0.80) with dominant C₂₉ regular steranes, consistent with an origin from terrigenous higher plant material mixed with marine algae deposited under suboxic conditions. This is also indicated by the presence of mixed amorphous and structured organic matter. This new geochemical data suggests that the analysed shales from the Napo Formation, especially the shales from the B limestone which contain Type II kerogen, have significant hydrocarbon potential in the eastern part of the Oriente Basin. The data may help to explain the distribution of hydrocarbon reserves in the east of the Oriente Basin, and also assist with the prediction of non‐structural traps.     

BURIAL AND THERMAL HISTORY MODELLING OF THE MANNAR BASIN,OFFSHORE SRI LANKA

The Mannar Basin is a Late Jurassic – Neogene rift basin located in the Gulf of Mannar between India and Sri Lanka which developed during the break‐up of Gondwana. Water depths in the Gulf of Mannar are up to about 3000 m. The stratigraphy is about 4 km thick in the north of the Mannar Basin and more than 6 km thick in the south. The occurrence of an active petroleum system in the basin was confirmed in 2011 by two natural gas discoveries following the drilling of the Dorado and Barracuda wells, located in the Sri Lankan part of the Gulf. However potential hydrocarbon source rocks have not been recorded by any of the wells so far drilled, and the petroleum system is poorly known. In this study, basin modelling techniques and measured vitrinite reflectance data were used to reconstruct the thermal and burial history of the northern part of the Mannar Basin along a 2D profile. Bottom‐hole temperature measurements indicate that the present‐day geothermal gradient in the northern Mannar Basin is around 24.4 ^oC/km. Optimised present‐day heat flows in the northern part of the Mannar Basin are 30–40 mW/m². The heat flow histories at the Pearl‐1 and Dorado‐North well locations were modelled using SIGMA‐2D software, assuming similar patterns of heat flow history. Maximum heat flows at the end of rifting (Maastrichtian) were estimated to be about 68–71 mW/m². Maturity modelling places the Jurassic and/or Lower Cretaceous interval in the oil and gas generation windows, and source rocks of this age therefore probably generated the thermogenic gas found at the Dorado and Barracuda wells. If the source rocks are organic‐rich and oil‐ and gas‐prone, they may have generated economic volumes of hydrocarbons.     

GEOCHEMICAL CHARACTERISTICS OF CRUDE OILS FROM THE SHARARA-C OIL FIELD,MURZUQ BASIN,SOUTHWESTERN LIBYA

Crude oil samples from the Sharara-C oil field (Concession NC-115, Murzuq Basin, SW Libya) were analysed by organic geochemical methods in order to infer the geochemical characteristics of their respective source rocks. Aromatic hydrocarbons were analysed by gas chromatography – mass spectrometry (GC-MS), and gas chromatography – tandem mass spectrometry (GC-MS-MS) was used to analyse saturated biomarkers. The Sharara-C oils are interpreted to have been generated by marine shales containing mixed terrigenous and marine organic materials deposited in an intermediate (suboxic) environment. Age-specific biomarker ratios indicated that the oils are older than Cretaceous, and maturation-related parameters pointed to their high thermal maturity. Consistent with previous studies, source rocks are inferred to be “hot” shales in the Lower Silurian Tanezzuft Formation. Almost all the parameter ratios calculated varied over a very narrow range, indicating that the investigated oils were compositionally similar. The only significant difference that was noted concerned the sterane/hopane ratios whose variation suggested that there was some variability in the composition of the source organic material. The organic geochemical parameters determined for the Sharara-C crude oils were compared with published data on other crude oils from Concession NC-115. Almost all the parameters agreed well with previously published data on oils from this part of the Murzuq Basin. The greatest deviation concerned the values of some of the maturity parameters. This tended to confirm the conclusions of previous studies concerning the presence of a number of distinct oil families and sub-families in the Sharara oil field area which are genetically related but which have different maturities.     

BURIAL AND THERMAL HISTORY MODELLING OF THE EDIACARAN SUCCESSION IN WESTERN AND SW UKRAINE AND MOLDOVA

The Ediacaran (Upper Neoproterozoic) succession in west and SW Ukraine and Moldova rests on a Cryogenian succession or basement. The succession is exposed at the surface along the southern margin of the Ukrainian Shield and dips to the SW towards the Carpathian Overthrust; where burial depths are sufficient, it is mature for oil and gas generation. The Ediacaran succession is made up of terrigenous siliciclastics ranging from conglomerates and sandstones to siltstones and mudstones, and includes a shale interval (the Kalus Beds) which may have source rock potential. Organic matter in the Kalus shales includes Vendotenides sp. (colonial bacteria) together with amorphous OM. This paper presents a study of the Kalus Beds and is based on data from surface and core samples and thin sections, and the results of Rock‐Eval pyrolysis and reflectance analyses. TOC contents in the Kalus shales are in general <0.5 wt%, although the measured TOC was 0.89 wt% and 0.84 wt%, respectively, in samples from the Sokal‐1 borehole and the Mynkivtsi outcrop location in SW Ukraine. The low present‐day TOC in borehole samples may be due to the thermal transformation of the OM originally present. Reflectivity as measured on vitrinite‐like macerals and bitumen in samples from outcrops ranges from 0.63 to 1.28% VR_oeq indicating a relatively low level of thermal maturity. However, the generally low TOC values in the outcrop samples mean that the Kalus Beds in general have little hydrocarbon potential in the study area. The burial and thermal history of the Ediacaran succession in SW Ukraine and the Moldovian Platform was reconstructed, and 1D modelling was carried out at the Brody‐1, Chernivtsi‐1, Dobrotvir‐1, Kolynkiv‐1, Litovyzh‐1, Ludyn‐1, Lyman‐1, Peremyshlyany‐1, Sokal‐1 and Voyutyn‐1 boreholes. The results of modelling indicate that maturities equivalent to the onset of the oil window were reached from the Early Devonian through the Early Carboniferous. Slightly higher modelled maturities occurred in boreholes located near the Teisseyre‐Tornquist Zone. The modelled transformation ratio for kerogen in the Kalus Beds is high and may exceed 90% in the boreholes studied.     

A RAPID METHOD OF QUANTIFYING THE RESOLUTION LIMITS OF HEAT-FLOW ESTIMATES IN BASIN MODELS

Deterministic forward models are commonly used to quantify the processes accompanying basin evolution. Here, we describe a workflow for the rapid calibration of palaeo heat‐flow behaviour. The method determines the heat‐flow history which best matches the observed data, such as vitrinite reflectance, which is used to indicate the thermal maturity of a sedimentary rock. A limiting factor in determining the heat‐flow history is the ability of the algorithm used in the software for the maturity calculation to resolve information inherent in the measured data. Thermal maturation is controlled by the temperature gradient in the basin over time and is therefore greatly affected by maximum burial depth. Calibration, i.e. finding the thermal history model which best fits the observed data (e.g. vitrinite reflectance), can be a time‐consuming exercise. To shorten this process, a simple pseudo‐inverse model is used to convert the complex thermal behaviour obtained from a basin simulator into more simple behaviour, using a relatively simple equation. By comparing the calculated “simple” maturation trend with the observed data points using the suggested workflow, it becomes relatively straightforward to evaluate the range within which a best‐fit model will be found. Reverse mapping from the simple model to the complex behaviour results in precise values for the heat‐flow which can then be applied to the basin model. The goodness‐of‐fit between the modelled and observed data can be represented by the Mean Squared Residual (MSR) during the calibration process. This parameter shows the mean squared difference between all measured data and the respective predicted maturities. A minimum MSR value indicates the “best fit”. Case studies are presented of two wells in the Horn Graben, Danish North Sea. In both wells calibrating the basin model using a constant heat‐flow over time is not justified, and a more complex thermal history must be considered. The pseudo‐inverse method was therefore applied iteratively to investigate more complex heat‐flow histories. Neither in the observed maturity data nor in the recorded stratigraphy was there evidence for erosion which would have influenced the present‐day thermal maturity pattern, and heat‐flow and time were therefore the only variables investigated. The aim was to determine the simplest “best‐fit” heat‐flow history which could be resolved at the maximum resolution given by the measured maturity data. The conclusion was that basin models in which the predicted maturity of sedimentary rocks is calibrated solely against observed vitrinite reflectance data cannot provide information on the timing of anomalies in the heat‐flow history. The pseudo inverse method, however, allowed the simplest heat‐flow history that best fits the observed data to be found.     

PETROLEUM GEOLOGY OF THE NOGAL BASIN AND SURROUNDING AREA,NORTHERN SOMALIA,PART 2: HYDROCARBON POTENTIAL

Seismic reflection profiles and well data show that the Nogal Basin, northern Somalia, has a structure and stratigraphy suitable for the generation and trapping of hydrocarbons. However, the data suggest that the Upper Jurassic Bihendula Group, which is the main source rock elsewhere in northern Somalia, is largely absent from the basin or is present only in the western part. The high geothermal gradient (～35–49 °C/km) and rapid increase of vitrinite reflectance with depth in the Upper Cretaceous succession indicate that the Gumburo Formation shales may locally have reached oil window maturity close to plutonic bodies. The Gumburo and Jesomma Formations include high quality reservoir sandstones and are sealed by transgressive mudstones and carbonates. ID petroleum systems modelling was performed at wells Nogal‐1 and Kalis‐1, with 2D modelling along seismic lines CS‐155 and CS‐229 which pass through the wells. Two source rock models (Bihendula and lower Gumburo) were considered at the Nogal‐1 well because the well did not penetrate the sequences below the Gumburo Formation. The two models generated significant hydrocarbon accumulations in tilted fault blocks within the Adigrat and Gumburo Formations. However, the model along the Kalis‐1 well generated only negligible volumes of hydrocarbons, implying that the hydrocarbon potential is higher in the western part of the Nogal Basin than in the east. Potential traps in the basin are rotated fault blocks and roll‐over anticlines which were mainly developed during Oligocene–Miocene rifting. The main exploration risks in the basin are the lack of the Upper Jurassic source and reservoirs rocks, and the uncertain maturity of the Upper Cretaceous Gumburo and Jesomma shales. In addition, Oligocene‐Miocene rift‐related deformation has resulted in trap breaching and the reactivation of Late Cretaceous faults.     

ORGANIC GEOCHEMISTRY AND PETROLOGY OF A LOWER JURASSIC (PLIENSBACHIAN) PETROLEUM SOURCE ROCK FROM AÏT MOUSSA,MIDDLE ATLAS,MOROCCO

Organic‐rich silty marls and limestones (Pliensbachian to earliest Toarcian) exposed at Aït Moussa in Boulemane Province are the only known example of an effective petroleum source rock in the Middle Atlas of Morocco. In this study, petrological and organic‐geochemical analyses (vitrinite reflectance measurements, Rock‐Eval pyrolysis, GC‐MS) were carried out in order to evaluate the maturity, quality and quantity of the organic matter (OM) and to investigate the depositional environment of these source rocks. Results indicate the presence of Type I/II kerogen which was deposited under marine conditions with an input of predominantly algal‐derived organic matter. The presence of woody particles indicates minor input of terrestrial material. Organic‐geochemical and biomarker analyses are consistent with deposition of carbonate‐rich sediments under oxygen‐depleted but not anoxic conditions. In terms of thermal maturity, the sediments have reached the oil window (0.5–0.6 %VR_t) but not peak oil generation, although petroleum generation and migration are indicated by organic geochemical and microscopic evidence. Kinetic parameters derived from an investigation of petroleum generation characteristics show that the kerogen decomposes within a narrow temperature interval due to the fairly homogenous structure of the algal‐derived organic matter. The kinetic parameters together with vitrinite reflectance data were used to construct a ID model of the burial, thermal and maturation history of the Aït Moussa locality. The model suggested that deepest burial (approx. 3200 m) for the Pliensbachian succession took place in the Eocene (approx. 40 Ma). Two phases of hydrocarbon generation occurred, the first in the Late Jurassic/Early Cretaceous (approx. 150 Ma), and the second at the time of deepest burial (Eocene).     

PART 1: ROCK-EVALFYROLYSIS AND VITRINITE REFLECTANCE1

Detailed organic geochemistry has been performed on a large number of Lower Mississippian-Upper Devonian Bakken shales from the North Dakota portion of the Williston Basin, and 28 oils mainly from Mississippian Madison Group rocks from different basinal areas. Here we report results of Rock-Eval pyrolysis and vitrinite reflectance (R_o) analyses. Variable paleoheat flows in the Williston Basin caused the threshold of intense hydrocarbon generation to occur at different depths in different basinal areas. In higher paleogeothermal gradient basinal areas, this event occurred at depths of 7,650-8,000 ft, and at 10,000 ft or deeper in lower paleogeothermal gradient areas of the Basin. Distinct organic metamorphic imprints in Williston Basin sediments were also caused by extreme, but variable, paleoheat flows in the basin, as well as secondary migration of crude oils from deep basinal source areas. The high paleoheat flows are postulated as being due to a Late Cretaceous — Paleocene aborted rift event. Only a small volume of Bakken shales in restricted areas of the Williston Basin was responsible for the oil found reservoired in Mississippian Madison Group rocks. However, this small shale volume has been responsible for a relatively large amount of crude oil. R₀ profiles in the Tertiary through Middle Jurassic rocks in the Williston Basin had steep, linear R_o versus depth gradients, with strong reversals of R₀ values occurring in the Lower Jurassic rocks. The lower Mesozoic through Paleozoic rocks of the Basin had strongly suppressed R₀ values compared to the values in the Tertiary through Middle Jurassic rocks. This was especially true of the R₀ values in the Bakken shales. This R₀ suppression was due to a change in organic matter (OM) type from oxygen-rich terrestrially derived OM in the younger rocks, to a hydrogen-rich marine derived OM in the deeper, older rocks. The threshold of intense oil generation (TIHG) occurred in the Bakken shales of the Williston Basin at R₀ values somewhere between 0.9 and 1.7% (best estimate 0.9), as would be read in oxygen-rich OM. Much higher burial temperatures (and consequently R₀ values) than usually held to be necessary were required for both the TIHG as well as mainstage hydrocarbon generation in the Bakken shales. These results are most likely applicable in general to source rocks with hydrogen-rich OM. The data of this study have major implications to petroleum exploration as well as to petroleum resource assessment.     

SUPPRESSION AND RETARDATION OF VITRINITE REFLECTANCE, PART 2. DERIVATION AND TESTING OF A KINETIC MODEL FOR SUPPRESSION

The presence of suppressed and retarded vitrinite reflectance (VR) data introduces a number of dificulties into the prediction of hydrocarbon generation in sedimentary basins. Although the effects of suppression can be removed from measured VR values manually, a kinetic model for suppressed vitrinite maturation would enable both suppressed and unsuppressed VR values to be predicted using thermal histories derived from basin modelling. The evaluation of hydrocarbon generation fiom suppressed and unsuppressed vitrinite shows that both have similar reaction kinetics. While hydrocarbon generation involves the rupture of the bonds holding volatiles into the vitrinite structure, increases in VR are mainly produced by aromatisation and condensation reactions which take place after volatiles have been expelled. The reactions involved in hydrocarbon generation are diyerent from those responsible for increases in VR, and it is not therefore appropriate to derive kinetic models of vitrinite maturation from laboratory hydrocarbon generation experiments. During the maturation of normal (unsuppressed) vitrinite, the volatiles generated are expelled via the microporous network; the expulsion efficiency is not limited by the capacity of the microporous network. In hydrogen‐rich (suppressed) vitrinites, excess volatiles saturate the microporous network, restricting further aromatisation and condensation processes within the vitrinite, which results in suppression of VR. Kinetically, this has been modelled by using a variable pre‐exponential or “A” value. Two versions of a kinetic model of vitrinite maturation (SMod‐1 and SMod‐2) have been prepared, based on the amount of suppression predicted by HI‐VR calibration models published by Lo (1993) and Samuels son and Middleton (1998). Two case studies, involving wells Bunga Orkid‐1 (Malay Basin) and 2013–4 (Outer Moray Firth, North Sea), are discussed. Both wells contain suppressed VR values; well 20/3–4 is also overpressured and contains VR data that are both retarded and suppressed. The application of the SMod model to the wells enables heat flow histories derived from tectonic (rift) histories to be used for the prediction of VR data, although in the case of well 20/3–4, the use of a pressure retardation model was also required. Complementary evidence to support the use of the heat flow history applied to well 2013–4 is provided by palaeotemperature data obtained from diagenetic concretions.     

鲁卜哈里盆地志留系热页岩特征及成熟度演化史

根据钻井资料,分析了鲁卜哈里盆地志留系底部热页岩在盆地内的发育状况。对岩心、岩屑样品进行了TOC测定、热解分析及镜质体反射率测定,认为热页岩演化已达成熟—高成熟阶段,有的甚至是过成熟阶段。对样品干酪根、沥青“A”及其族组分的碳同位素分析,确定了有机质类型为II型。利用PetroMod盆地模拟软件,对3口探井进行埋藏史、热史和成熟度史模拟,并对对外合作区块热页岩进行成熟度演化史模拟,认为该区块志留系底部热页岩由深凹至东部斜坡各阶段的演化时间依次变晚,凹陷区热页岩在早二叠世均已进入成熟演化阶段;而东部斜坡热页岩于早三叠世末—晚侏罗世末期才进入成熟演化阶段。