BURIAL AND THERMAL HISTORY MODELLING OF THE MURZUQ AND GHADAMES BASINS (LIBYA) USING THE GALO COMPUTER PROGRAMME

The GALO computer programme was used to model the thermal and burial histories of the Murzuq and Ghadames Basins, Libya. The model was based on recent drilling and seismic data from the basins, and used published deep temperature and vitrinite reflectance measurements. The model provides more accurate results than previous studies which were based on constant geothermal gradients during the basins' histories, and variations in heat flux at the base of the sedimentary cover were chosen so that calculated values of vitrinite reflectance coincide with those observed. The Murzuq Basin and Libyan part of the Ghadames Basin contain similar source rock units but have different burial histories. In the Murzuq Basin, maximum present‐day burial depths of Cambrian sediments range from 2200 to 2800 m and only locally reach 3000 – 3600 m; in the Ghadames Basin, however, burial depths can exceed 4–5 km. The burial history of the Murzuq Basin includes several periods of intense erosion and lithospheric heating which produced significant lateral variations in thermal maturity, leading in places to unexpected results. For example, relatively shallow‐buried Lower Silurian source rocks in the A‐76 area on the flank of the Murzuq Basin have a thermal maturity of R_o = 1.24% which is higher than the maturity of the same interval in more deeply buried areas (wells D1‐NC‐58 or J1‐NC101). In the central part of the Ghadames Basin, the modelling suggests a higher level of thermal maturity for organic matter in Silurian strata (R_o 0.8 to 1.3%), confirming the generation potential of Lower Silurian “hot shales”. Significant hydrocarbon generation began here in the Late Carboniferous and continues at the present day. Modelling of the Late Devonian (Frasnian) Aouinat Ouinine Formation “hot shales” suggests limited hydrocarbon generation depending strongly on burial depth, with the main phase of hydrocarbon generation taking place during the final episode of thermal activation in the Cenozoic. In the wells studied in the Ghadames Basin, the “oil window” extends over a considerable part of the present‐day sedimentary column.     

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.     

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.     

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.     

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.     

IMPACT OF MAGMATISM ON PETROLEUM SYSTEMS IN THE SVERDRUP BASIN, CANADIAN ARCTIC ISLANDS, NUNAVUT: A NUMERICAL MODELLING STUDY

Numerical modelling is used to investigate for the first time the interactions between a petroleum system and sill intrusion in the NE Sverdrup Basin, Canadian Arctic Archipelago. Although hydrocarbonexploration has been successful in the western Sverdrup Basin, the results in the NE part of thebasin have been disappointing, despite the presence of suitable Mesozoic source rocks, migrationpaths and structural/stratigraphic traps, many involving evaporites. This was explained by (i) theformation of structural traps during basin inversion in the Eocene, after the main phase ofhydrocarbon generation, and/or (ii) the presence of evaporite diapirs locally modifying the geothermalgradient, leading to thermal overmaturity of hydrocarbons. This study is the first attempt at modellingthe intrusion of Cretaceous sills in the east‐central Sverdrup Basin, and to investigate how theymay have affected the petroleum system. A one‐dimensional numerical model, constructed using PetroMod9.0®, investigates the effectsof rifting and magmatic events on the thermal history and on petroleum generation at the DepotPoint L‐24 well, eastern Axel Heiberg Island (79°23′40″N, 85°44′22″W). The thermal history isconstrained by vitrinite reflectance and fission‐track data, and by the tectonic history. The simulationidentifies the time intervals during which hydrocarbons were generated, and illustrates the interplaybetween hydrocarbon production and igneous activity at the time of sill intrusion during the EarlyCretaceous. The comparison of the petroleum and magmatic systems in the context of previouslyproposed models of basin evolution and renewed tectonism was an essential step in the interpretationof the results from the Depot Point L‐24 well. The model results show that an episode of minor renewed rifting and widespread sill intrusionin the Early Cretaceous occurred after hydrocarbon generation ceased at about 220 Ma in theHare Fiord and Van Hauen Formations. We conclude that the generation potential of these deeperformations in the eastern Sverdrup Basin was not likely to have been affected by the intrusion ofmafic sills during the Early Cretaceous. However, the model suggests that in shallower sourcerocks such as the Blaa Mountain Formation, rapid generation of natural gas occurred at 125 Ma, contemporaneous with tectonic rejuvenation and sill intrusion in the east‐central Sverdrup Basin.A sensitivity study shows that the emplacement of sills increased the hydrocarbon generation ratesin the Blaa Mountain Formation, and facilitated the production of gas rather than oil.     

NUMERICAL MODELLING OF THE AUSTRALIA – ANTARCTICA CONJUGATE MARGINS USING THE GALO SYSTEM: PART 2. THERMAL AND MATURATION HISTORY OF THE MAWSON SEA BASIN,EAST ANTARCTICA

The thermal evolution of the Mawson Sea Basin, offshore East Antarctic, was modelled using the GALO basin modelling programme. As there exist no deep temperature or vitrinite reflectance data for the Mawson Sea Basin, the simulation was based on a limited nonthermal database. This includes the present-day sedimentary section along a multichannel seismic profile which crosses the western part of the Mawson Sea along with geophysical assessments of the depth of the Moho. An analysis of the variations in tectonic subsidence was used to estimate the duration and magnitude of thermal activation or stretching of the lithosphere. This analysis suggested that a proportion of the lithospheric stretching took place before the start of synrift sediment deposition at about 160 Ma (Late Jurassic). This pre-sedimentation lithospheric stretching has been ignored in previous studies, resulting in significant underestimation of the total stretching which has occurred. The analysis also suggests that the thermal maturity of Lower Jurassic potential source rocks along the profile may reach and even exceed the onset of the oil generation window, whereas source rocks in less deeply buried parts of the profile are less mature. In general, the results of the modelling indicate that the Mawson Sea Basin is a promising area for future oil and gas exploration.     

HYDROCARBON ACCUMULATION PROCESSES IN THE YANGTAKE FOLDBELT,KUQA FORELAND BASIN,NW CHINA: INSIGHTS FROM INTEGRATED BASIN MODELLING AND FLUID INCLUSION ANALYSES

Abundant gas and condensate resources are present in the Kuqa foreland basin in the northern Tarim Basin, NW China. Most of the hydrocarbons so far discovered are located in foldbelts in the north and centre of the foreland basin, and the Southern Slope region has therefore been less studied. This paper focusses on the Yangtake area in the west of the Southern Slope. Basin modelling was integrated with fluid inclusion analyses to investigate the oil and gas charge history of the area. ID modelling at two widely spaced wells (DB‐1 and YN‐2) assessed the burial, thermal and hydrocarbon generation histories of Jurassic source rocks in the foreland basin. Results show that the source rocks began to generate hydrocarbons (R_o >0.5%) during the Miocene. In both wells, the source rocks became mature to highly mature between 12 and 1.8 Ma, and most oil and gas was generated at 5.3–1.8 Ma with peak generation at about 3 Ma. Two types of petroleum fluid inclusions were observed in Cretaceous and lower Paleocene sandstone reservoir rocks at wells YTK‐5 and YTK‐1 in the Yangtake area. The inclusions in general occur along healed microfractures in quartz grains, and have either yellowish or blueish fluorescence colours. Aqueous inclusions coexisting with both types of oil inclusions in Cretaceous sandstones in well YTK‐5 had homogenization temperatures of 96–128 °C and 115–135 °C, respectively. The integrated results of this study suggest that oil generated by the Middle Jurassic Qiakemake Formation source rocks initially charged sandstone reservoirs in the Yangtake area at about 4 Ma, forming the yellowish‐fluorescing oil inclusions. Gas, which was mainly sourced from Lower Jurassic Yangxia and Middle Jurassic Kezilenuer coaly and mudstone source rocks, initially migrated into the same reservoirs in the Yangtake area at about 3.5 Ma and interacted with the early‐formed oils forming blueish‐fluorescing oil inclusions. The migration of gas also resulted in formation of the condensate accumulations which are present at the YTK‐1 and YTK‐2 fields in the Yangtake area.     

HYDROCARBON SEEPAGE GENERATION AND MIGRATION IN THE SOUTHERN GULF OF SUEZ, EGYPT: INSIGHTS FROM BIOMARKER CHARACTERISTICS AND SOURCE ROCK MODELLING

Active oil seepages in the Gebel El-Zeit area (southern Gulf of Suez, Egypt) occur in fault zones on the western flank of the East Zeit Basin. Gas chromatography-mass spectrometry indicates that these oils are rich in tricyclic terpanes and extended hopanes with few diasteranes. These characteristics are typical of oils derived from marine siliciclastic source rocks; an input of terrestrial angiosperms material is indicated by the very high oleanane index of 32.65% and the low gammacerane index of 6.28%. The molecular maturity parameter C₂₉ααα cholestane [20S/(20S+20R)] is < 0.5 indicating that these oils were generated at relatively low thermal maturities. The seepage oils resemble Miocene crude oils in the East Zeit Basin which are believed to be generated from the Lower Miocene Rudeis Shale. Burial history modelling indicates that oil generation from this unit began at around 3–4 Ma at vitrinite reflectance levels of Ro%=0.60–0.85. This implies extensive lateral and vertical migration has taken place for the generated oil to reach the surface. Alternatively, the seepage oils may be sourced by leakage from preexisting accumulations.     

THE PETROLEUM SYSTEM IN THE SANDINO FOREARC BASIN, OFFSHORE WESTERN NICARAGUA

The underexplored Sandino Basin (Nicaragua Basin/Trough) is located within the forearc area of western Nicaragua and NW Costa Rica. Exploration activity since 2004 has focussed on the onshore sector of the basin, and has included the first drilling campaign for over 30 years. Recent 2D basin modelling of the offshore sector together with organic geochemical studies has attempted to reassess the basin's petroleum potential. Geochemical data from the deepest offshore well indicate that Middle Eocene to Lower Oligocene sediments of the Brito Formation, as well as Upper Oligocene to Lower Miocene sediments of the Masachapa Formation, may have source rock potential. A third and perhaps more significant potential source rock interval is associated with the Lower Cretaceous black shales of the Loma Chumico Formation, which has been studied in the adjacent forearc area in NW Costa Rica (Tempisque Basin) and is inferred to be present in the Sandino Basin.
The thermal history of the forearc basin is controlled by the low basal heat flow (39 mW/m²). 2D modelling has shown that the Sandino Basin is thermally mature, resulting in the potential for hydrocarbon generation in organic-rich intervals in the Brito and Masachapa Formations. A petroleum-generating "kitchen" has tentatively been identified on a NE-SW seismic section which crosses the basin. Modelling suggests that this kitchen has been active from the Late Eocene until the present day, and that the main phases of petroleum generation in general coincide with phases of maximum subsidence in the Late Eocene, Late Oligocene and Plio-Pleistocene. Hydrocarbon migration most probably occurred from the deep basin towards the flanks. Significant volumes of petroleum may have been lost prior to the Late Miocene before the formation of a coastal flexure which can be recognised in the NE of the seismic profile.     

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.     

THE THERMAL GRADIENT HISTORY OF THE THRACE BASIN, NW TURKEY: CORRELATION WITH BASIN EVOLUTION PROCESSES

Thermal maturity modelling is widely used in basin modelling to help assess the exploration risk. Of the calibration algorithms available, the Easy%Ro model has gained wide acceptance. In this study, thermal gradients at 70 wells in the Thrace Basin, NW Turkey, were calibrated against vitrinite reflectance (%Ro) using the Easy%Ro model combined with an inverse scheme. The mean squared residual (MSR) was used as a quantitative measure of mismatch between the modelled and measured %Ro. A 90% confidence interval was constructed on the mean of squared residuals to assess uncertainty. The best thermal gradient (i.e. minimum MSR) was obtained from the MSR curve for each well, and an average palaeo‐thermal gradient map of the Thrace Basin was therefore created. Calculated thermal gradients were compared to the results of previous studies. A comparison of modelled palaeo‐thermal gradients with those measured at the present day showed that the thermal regime of the Thrace Basin has not changed significantly during the basin's history. The geological and thermal characteristics of the Thrace Basin were compared and the thermal anomalies were evaluated as a function of basin evolution processes. The basin's thermal regime was controlled by: (1) basement edge effects; (2) crustal thickness and basement heat flows; (3) thermal conductivity variations within the stratigraphic column; (4) transient heat flow effects; and (5) the influence of tectonic features. The impact of these factors on variations in the thermal gradients is discussed in detail. Basement edge effects are most marked on the steep northern margin of the basin where heat is preferentially retained in highly conductive basement rocks rather than being transferred into less conductive sedimentary rocks. Thus, heat is significantly focused onto the northern edge of the basement, resulting in a thermal anomaly along the northern basin margin. The margins of the basin, with relatively thick upper crust, have relatively higher thermal gradients compared to the central areas. This is due to radiogenic heat production in the upper crust. Thus, thermal gradients increase above highs and at the margins where thicker upper crust is present. A heat flow map of the Thrace Basin, constructed using a basin‐scale crustal thickness map and a basement heat‐flow algorithm, is presented and demonstrates the heat generation potential of the upper crust. The Eocene Ceylan Formation, which has relatively low thermal conductivity, significantly reduces the thermal gradients by blocking heat transferred from the basement. Areas of high sedimentation rate are associated with low thermal gradients due to the transient heat flow effects of young, thick and “thermally immature” sediments as a function of the heat capacities of these deposits. A direct relationship between thermal gradients and major structural trends could not be established because of a number of factors including the inactivity of the subsurface Miocene fault systems, which did not allow the flow of high temperature fluids through to shallow depths; also, the steady burial and sedimentation rates since the Early Eocene have maintained the pressure system in equilibrium.     

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).     

PETROLEUM GEOLOGY OF THE NOGAL BASIN AND SURROUNDING AREA,NORTHERN SOMALIA: PART 1, STRATIGRAPHY AND TECTONIC EVOLUTION

In this study, 92 closely‐spaced reflection seismic profiles (～4000 line‐km) were tied to biostratigraphic and lithological data from six deep exploration wells in the poorly‐known Nogal rift basin, northern Somalia, and were integrated with outcrop and aeromagnetic data to investigate the basin stratigraphy and tectonic evolution. Aeromagnetic data show NW‐SE trending magnetic anomalies which are interpreted as plutonic bodies intruded during the Early Cretaceous, probably contemporaneously with a pre‐Cenomanian uplift phase. The aeromagnetic data also suggest a change of basement type from Inda Ad Series metasediments in the SE of the study area to igneous and high‐grade metamorphic basement in the NW. Biostratigraphic data and seismic reflection profiles define the Nogal Basin as a WNW–ESE striking half‐graben, approximately 250 km long and 40 km wide, which formed as a result of mainly Cenomanian–Maastrichtian and Oligocene–Miocene intracontinental rifting. The depocentre contains at least 7000 m of Mesozoic and Cenozoic sediments and is located in the centre of the basin (east of well Nogal‐1), to the south of the Shileh Madu Range. To the north, the basin is bounded by a major border fault along which significant variations in the thickness of sedimentary units are observed, suggesting that the fault controlled basin architecture and patterns of sedimentation. Oligocene–Miocene normal faults which resulted in north‐tilted fault blocks are widespread within the main basin; smaller‐scale sub‐basins oriented NW‐SE to WNW‐ESE are observed to the NW of the basin and probably developed contemporaneously. The Late Jurassic rift phase which has been documented elsewhere in northern Somalia is either missing in the Nogal Basin or is preserved only in localised grabens in the western and central parts of the basin. This is probably due to the pre‐Cenomanian uplift and erosion which removed almost the entire Jurassic and Lower Cretaceous successions over a wide area referred to as the Nogal‐Erigavo Arch. A more pronounced rifting episode followed this erosional event in the Cenomanian–Maastrichtian and resulted in the deposition of well‐sorted fluvio‐deltaic sandstones (Gumburo and Jesomma Formations), more than 2000 m thick. In wells in the Nogal Basin, these formations are between two and three times thicker than in wells drilled in footwall locations, and include excellent reservoir rocks sealed by transgressive mudstones and carbonates. A final rifting event in the Oligocene–Miocene was related to the opening of the Gulf of Aden. A rift sag phase which accommodated the Early Oligocene continental sediments of the Nogal Group initially developed at the centre of the basin. This was followed by a period of strong rotational faulting and tilting, which reactivated the Cenomanian–Maastrichtian structures.     

TEMPERATURE AND BURIAL HISTORY MODELLING OF THE DRMNO AND MARKOVAC DEPRESSIONS, SE PANNONIAN BASIN, SERBIA

We have modelled the subsidence, thermal and maturation history of the Drmno and Markovac depressions in the SE Pannonian Basin (Serbia) in order to calculate quantities of generated, expelled and migrated hydrocarbons. Stratigraphic, lithofacies, structural, thermal and geochemical data were used to create a conceptual model of the basin's evolution to depths of 5,000m. The models were calibrated using present-day temperature and vitrinite reflectance data from representative wells. The results show that in the centres of these depressions, possible Badenian and pre-Badenian (i.e. Middle and Lower Miocene) source rocks are sufficiently mature to have generated oil and gas.
Maturity data reveal significant differences in heat flow during times when maximum palaeotemperatures were reached. From these data high heat flows can only be deduced for some of the wells, whereas similar high heat flows are deduced from present-day temperature data. Future research is necessary to resolve in detail the geologic evolution of the study area which resulted in the significant differences between the Mio/Pliocene and Recent heat flows.
Petroleum generation is taking place at depths below 2,000m in both depressions, mainly from Pre-Badenian source rocks which contain Type II-III kerogen and which appear to have a high petroleum generation potential.     

MATURITY AND PETROLEUM SYSTEMS MODELLING IN THE OFFSHORE ZAMBEZI DELTA DEPRESSION AND ANGOCHE BASIN,NORTHERN MOZAMBIQUE

Petroleum systems analysis and maturity modelling is used to predict the timing and locations of hydrocarbon generation in the underexplored offshore Zambezi Delta depression and Angoche basin, northern Mozambique. Model inputs include available geological, geochemical and geophysical data. Based on recent plate‐tectonic reconstructions and regional correlations, the presence of Valanginian and Middle and/or Late Jurassic marine source rock is proposed in the study area. The stratigraphy of the Mozambique margin was interpreted along reflection seismic lines and tied to four wells in the Zambezi Delta depression. Thermal maturity was calibrated against measured vitrinite reflectance values from these four wells. Four 1‐D models with calibration data were constructed, together with another five without calibration data at pseudo‐well locations, and indicate the maturity of possible source rocks in the Zambezi Delta depressions and Angoche basin. Two 2‐D petroleum systems models, constrained by seismic reflection data, depict the burial history and maturity evolution of the Zambezi Delta basin. With the exception of the deeply‐buried centre of the Zambezi Delta depression where potential Jurassic and Lower Cretaceous source rocks were found to be overmature for both oil and gas, modelling showed that potential source rocks in the remaining parts of the study area are mature for hydrocarbon generation. In both the Zambezi Delta depression and Angoche basin, indications for natural gas may be explained by early maturation of oil‐prone source rocks and secondary oil cracking, which likely began in the Early Cretaceous. In distal parts of the Angoche basin, however, the proposed source rocks remain in the oil window.     

Source rock evaluation of shale intervals of the Kurra Chine Formation,Kurdistan Region-Iraq: An organic geochemical and basin modeling approach

This work reports on the source rock potential and 1D-basin modeling of the Kurra Chine Formation (Late Triassic) in Northern Iraq, northeast of Duhok province. Tectonically, the area is a part of the Zagros Fold and Thrust Belt, and within the High Folded Zone of Iraqi tectonic division. The Total Organic Carbon (TOC%) values for the shale intervals indicating a fair to good organic carbon content. The Kerogen is a mixed type II-III and III. The Tmax values displays that organic matter of Kurra Chine Formation is thermally mature and it is in main oil window. From a plot of modelled vitrinite reflectance (VR) versus time, is concluded that the organic matter of the Kurra Chine Formation entered the early oil window (EOW) in the Early Cretaceous (143 Ma) and reached the peak oil window around 130 Ma ago. During the Miocene (at 14 Ma) the organic matter entered late oil window. Modelling also indicates that the onset of oil generation was in the Early Cretaceous in which 45% conversion was achieved in the Middle Miocene. Based on the current study, the shale units of the Kurra Chine Formation can be regarded as potential source rocks that are thermally mature and capable of generating hydrocarbons; however, due to uplift and unroofing, generation of hydrocarbons has ceased at present day.     

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 AND MATURATION HISTORY OF THE HEGLIG FIELD AREA, MUGLAD BASIN, SUDAN

The NW‐SE trending Muglad Basin (SW Sudan) is one of a number of Mesozoic basins which together make up the Central African Rift System. Three phases of rifting occurred during the Cretaceous and Tertiary, resulting in the deposition of at least 13 km of sediments in this basin. Commercial hydrocarbons are sourced from the Barremian‐Neocomian Sharaf Formation and the Aptian‐Albian Abu Gabra Formation. The Heglig field is located on a NW‐SE oriented structural high in the SE of the Muglad Basin, and is the second‐largest commercial oil discovery in Sudan. The high is characterised by the presence of rotated fault blocks, and is surrounded by sub‐basinal structural lows. We modelled the geohistories of three wells on different fault blocks in the Heglig field (Heglig‐2, Barki‐1 and Kanga‐1) and one well in the Kaikang Trough (May25–1). The models were calibrated to measured porosity‐depth data, temperature and vitrinite reflectance measurements. Predicted present‐day heat flow over this part of the Muglad Basin is about 55 mW/m². However, a constant heat‐flow model with this value did not result in a good fit between calculated vitrinite Ro and measured Ro at the wells studied. Therefore a variable heat‐flow model was used; heat flow peaks of 75, 70 and 70 mW/m² were modelled, these maxima corresponding to the three synrift phases. This model resulted in a better fit between calculated and measured Ro. The source rock section in the Sharaf and Abu Gabra Formations was modelled for hydrocarbon generation in the four wells. Model results indicate that the present‐day oil generation window in the Hegligfield area lies at depths of between 2 and 4 km, and that oil and gas generation from the basal unit of the Abu Gabra Formation occurred between about 90 and 55 Ma and from the Sharaf Formation between 120 and 50 Ma. The results suggest that the oils discovered in the Heglig area have been generated from a deep, mature as‐yet unpenetrated source‐rock section, and/or from source rocks in nearby sub‐ basinal areas.     

松辽盆地东南隆起氧化作用与有机质的演化

有机质在遭受氧化作用后,其元素的组成比例、最高热解峰温、生烃转化率及镜质体反射率均发生了较大的变化,常规判识有机质演化程度的指标已失去意义。松辽盆地东南隆起区的研究结果表明 :有机质在遭受氧化作用影响后,干酪根元素的O/C比随演化程度的加深而迅速降低,致使其反映的演化程度高于实际值;有机质氧化后,导致T^max增高;经过氧化的有机质在相同的热力条件下,具有较高的转化率;在强氧化作用下形成的镜质体,其反射率值比正常情况下增长大,强还原环境下则减小。因此,在研究松辽盆地东南隆起区的有机质演化,特别是营城组的演化时,不能以某一指标而定论。