Thermal maturity history and petroleum generation modelling for the Lower Cretaceous Abu Gabra Formation in the Fula Sub-basin,Muglad Basin,Sudan

Two petroleum source rock intervals of the Lower Cretaceous Abu Gabra Formation at six locations within the Fula Sub-basin, Muglad Basin, Sudan, were selected for comprehensive modelling of burial history, petroleum maturation and expulsion of the generated hydrocarbons throughout the Fula Sub-basin. Locations (of wells) selected include three in the deepest parts of the area (Keyi oilfield); and three at relatively shallow locations (Moga oilfield). The chosen wells were drilled to depths that penetrated a significant part of the geological section of interest, where samples were available for geochemical and source rock analysis. Vitrinite reflectances (Ro %) were measured to aid in calibrating the developed maturation models.The Abu Gabra Formation of the Muglad Basin is stratigraphically subdivided into three units (Abu Gabra-lower, Abu Gabra-middle and Abu Gabra-upper, from the oldest to youngest). The lower and upper Abu Gabra are believed to be the major source rocks in the province and generally contain more than 2.0 wt% TOC; thus indicating a very good to excellent hydrocarbon generative potential. They mainly contain Type I kerogen. Vitrinite reflectance values range from 0.59 to 0.76% Ro, indicating the oil window has just been reached. In general, the thermal maturity of the Abu Gabra source rocks is highest in the Abu Gabra-lower (deep western part) of the Keyi area and decreases to the east toward the Moga oilfied at the Fula Sub-basin.Maturity and hydrocarbon generation modelling indicates that, in the Abu Gabra-Lower, early oil generation began from the Middle- Late Cretaceous to late Paleocene time (82.0–58Ma). Main oil generation started about 58 Ma ago and continues until the present day. In the Abu Gabra-upper, oil generation began from the end of the Cretaceous to early Eocene time (66.0–52Ma). Only in one location (Keyi-N1 well) did the Abu Gabra-upper reach the main oil stage. Oil expulsion has occurred only from the Abu Gabra-lower unit at Keyi-N1 during the early Miocene (>50% transformation ratio TR) continuing to present-day (20.0–0.0 Ma). Neither unit has generated gas. Oil generation and expulsion from the Abu Gabra source rocks occurred after the deposition of seal rocks of the Aradeiba Formation.     

Petroleum source rock characterisation and hydrocarbon generation modeling of the Cretaceous sediments in the Jiza sub-basin,eastern Yemen

Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S₁ + S₂) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin.     

鄂尔多斯盆地塔巴庙地区上古生界源岩热演化特征

鄂尔多斯盆地北部主力气源岩太原组、山西组煤系地层热成熟史的研究对本区天然气充注过程和有利目标区预测具有重要的参考价值。在对研究区烃源岩评价和一维、二维地质建模研究的基础上。利用BasinMod盆地模拟软件对单井以及研究区内二维剖面、平面进行了煤系烃源岩热演化史模拟研究。研究结果表明：（1）该区在中三叠世进入生烃门限，中侏罗世以后，烃源岩持续埋深，早白垩世末期至最大埋深（4000m左右），绝大多数的天然气都在这一阶段生成，早白垩世末构造抬升以后只有少量天然气生成；（2）研究区上古生界太原组和山西组煤系源岩最大累积生烃强度可达到2200×10^8m^3／km^2，对现今天然气的分布具有较强的控制作用。     

Geochemical characteristics and hydrocarbon generation modeling of the Jurassic source rocks in the Shoushan Basin, north Western Desert, Egypt

The Shoushan Basin is an important hydrocarbon province in the Western Desert, Egypt, but the origin of the hydrocarbons is not fully understood. In this study, organic matter content, type and maturity of the Jurassic source rocks exposed in the Shoushan Basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. The Jurassic source rock succession comprises the Ras Qattara and Khatatba Formations, which are composed mainly of shales and sandstones with coal seams. The TOC contents are high and reached a maximum up to 50%. The TOC values of the Ras Qattara Formation range from 2 to 54 wt.%, while Khatatba Formation has TOC values in the range 1-47 wt.%. The Ras Qattara and Khatatba Formations have HI values ranging from 90 to 261 mgHC/gTOC, suggesting Types II-III and III kerogen. Vitrinite reflectance values range between 0.79 and 1.12 VRr %. Rock−Eval T_max values in the range 438-458 °C indicate a thermal maturity level sufficient for hydrocarbon generation. Thermal and burial history models indicate that the Jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the Late Cretaceous to Tertiary. Hydrocarbon generation began in the Late Cretaceous and maximum rates of oil with significant gas have been generated during the early Tertiary (Paleogene). The peak gas generation occurred during the late Tertiary (Neogene).     

东海陆架盆地丽水—椒江凹陷月桂峰组烃源岩特征及生排烃史

丽水—椒江凹陷是东海陆架盆地油气勘探的一个重要领域,目前处于较低的油气勘探阶段。基于现有地质资料,在烃源岩发育特征及有机质丰度、类型和成熟度分析的基础上,采用含油气盆地数值模拟技术,定量恢复了研究区月桂峰组烃源岩的生排烃史。结果表明,月桂峰组烃源岩有机质丰度高,有机质类型以Ⅱ1型和Ⅱ2型为主,具有油气兼生的能力,总体上处于成熟阶段和高成熟阶段;月桂峰组烃源岩具有较高的生排烃强度,总体上经历了2次生排烃过程,但在不同构造单元存在明显的差异性。总之,以月桂峰组烃源岩为油气来源的含油气系统是该区油气勘探的主要目标。     

Tracing of deeply-buried source rock: A case study of the WC9-2 petroleum pool in the Pearl River Mouth Basin, South China Sea

The identification of a deeply-buried petroleum-source rock, owing to the difficulty in sample collection, has become a difficult task for establishing its relationship with discovered petroleum pools and evaluating its exploration potential in a petroleum-bearing basin. This paper proposes an approach to trace a deeply-buried source rock. The essential points include: determination of the petroleum-charging time of a reservoir, reconstruction of the petroleum generation history of its possible source rocks, establishment of the spatial connection between the source rocks and the reservoir over its geological history, identification of its effective source rock and the petroleum system from source to trap, and evaluation of petroleum potential from the deeply-buried source rock. A case study of the W9-2 petroleum pool in the Wenchang A sag of the Pearl River Mouth Basin, South China Sea was conducted using this approach. The W9-2 reservoir produces condensate oil and gas, sourced from deeply-buried source rocks. The reservoir consists of a few sets of sandstone in the Zhuhai Formation, and the possible source rocks include an early Oligocene Enping Formation mudstone and a late Eocene Wenchang Formation mudstone, with a current burial depth from 5000 to 9000 m. The fluid inclusion data from the reservoir rock indicate the oil and the gas charged the reservoir about 18–3.5 Ma and after 4.5 Ma, respectively. The kinetic modeling results show that the main stages of oil generation of the Wenchang mudstone and the Enping mudstone occurred during 28–20 Ma and 20–12 Ma, respectively, and that the δ¹³C₁ value of the gas generated from the Enping mudstone has a better match with that of the reservoir gas than the gas from the Wenchang mudstone. Results from a 2D basin modeling further indicate that the petroleum from the Enping mudstone migrated upward along the well-developed syn-sedimentary faults in the central area of the sag into the reservoir, but that the petroleum from the Wenchang mudstone migrated laterally first toward the marginal faults of the sag and then migrated upward along the faults into shallow strata. The present results suggest that the trap structure in the central area of the sag is a favorable place for the accumulation of the Enping mudstone-derived petroleum, and that the Wenchang mudstone-derived petroleum would have a contribution to the structures along the deep faults as well as in the uplifted area around the sag.     

Thermal evolution of the Kuh-e-Asmari and Sim anticlines in the Zagros fold-and-thrust belt: Implications for hydrocarbon generation

Mixed layer clay minerals, vitrinite reflectance and geochemical data from Rock-Eval pyrolysis were used to constrain the burial evolution of the Mesozoic–Cenozoic successions exposed at the Kuh-e-Asmari (Dezful Embayment) and Sim anticlines (Fars province) in the Zagros fold-and-thrust belt. In both areas, Late Cretaceous to Pliocene rocks, show low levels of thermal maturity in the immature stages of hydrocarbon generation and early diagenetic conditions (R0 I–S and R_o% values < 0.5). At depths of 2–4 km, T_max values (435–450 °C) from organic-rich layers of the Sargelu, Garau and Kazhdumi source rocks in the Kuh-e-Asmari anticline indicate mid to late mature stages of hydrocarbon generation. One dimensional thermal models allowed us to define the onset of oil generation for the Middle Jurassic to Eocene source rocks and pointed out that sedimentary burial is the main factor responsible for measured levels of thermal maturity. Specifically, the Sargelu and Garau Formations entered the oil window prior to Zagros folding in Late Cretaceous times, the Kazhdumi Formation during middle Miocene (syn-folding stage), and the Pabdeh Formation in the Late Miocene–Pliocene after the Zagros folding. In the end, the present-day distribution of oil fields in the Dezful Embayment and gas fields in the Fars region is primarily controlled by lithofacies changes and organic matter preservation at the time of source rock sedimentation. Burial conditions during Zagros folding had minor to negligible influence.     

2D basin modeling study of the Binak Trough,northwestern Persian Gulf,Iran

The northwestern part of the Persian Gulf is one of the most prominent hydrocarbon exploration and production areas. Oilfields are located in structural highs formed around the Cenomanian depression known as Binak Trough. To evaluate the highly variable source rock maturity, timing of hydrocarbon generation as well as migration pattern and the remaining hydrocarbon potential of the early Cretaceous source rocks, burial and thermal histories were constructed for four production wells and one pseudo well. In addition two cross sections covering the depression and the structural highs around the trough were investigated by 2D basin modeling to provide a better regional overview on basin evolution.The modeling results indicate that whereas the Cretaceous source rocks are immature or early mature at the location of oilfields, they reached sufficient maturity to generate and expel considerable amounts of hydrocarbons in the Binak depression. The main phase of oil generation and expulsion from the Cretaceous source rocks is relatively recent and thus highly favorable for the conservation of hydrocarbon accumulations. Trap charging occurred through the late Miocene to Pliocene after the Zagros folding. 2D models predict that the Albian source rock still has significant hydrocarbon generation potential whereas the lower Neocomian source rock has reached already a high transformation ratio within the deep kitchen area. Oil migration occurs in both lateral and vertical directions. This migration pattern could explain the distribution of identified oil families in the northwestern part of the Persian Gulf.     

Generation characteristics of Mesozoic syn- and post-rift source rocks,Bonaparte Basin,Australia: New insights from compositional kinetic modelling

Potential source rocks on the Laminaria High, a region of the northern Bonaparte Basin on the North West Shelf of Australia, occur within the Middle Jurassic to Lower Cretaceous early to post-rift sequences. Twenty-two representative immature source rock samples from the Jurassic to Lower Cretaceous (Plover, Laminaria, Frigate, Flamingo and Echuca Shoals) sequences were analysed to define the hydrocarbon products that analogous mature source rocks could have generated during thermal maturation and filled the petroleum reservoirs in the Laminaria High region. Rock-Eval pyrolysis data indicate that all the source rocks contain type II–III organic matter and vary in organic richness and quality. Open system pyrolysis-gas chromatography on extracted rock samples show a dominance of aliphatic components in the pyrolysates. The Plover source rocks are the exception which exhibit high phenolic contents due to their predominant land-plant contribution. Most of the kerogens have the potential to generate Paraffinic–Naphthenic–Aromatic oils with low wax contents. Bulk kinetic analyses reveal a relatively broad distribution of activation energies that are directly related to the heterogeneity in the kerogens. These kinetic parameters suggest different degrees of thermal stability, with the predicted commencement of petroleum generation under geological heating conditions covering a relatively broad temperature range from 95 to 135 °C for the Upper Jurassic−Lower Cretaceous source rocks. Both shales and coals of the Middle Jurassic Plover Formation have the potential to generate oil at relatively higher temperatures (140–145 °C) than those measured for crude oils in previous studies. Hence, the Frigate and the Flamingo formations are the main potential sources of oils reservoired in the Laminaria and Corallina fields. Apart from being a reservoir, the Laminaria Formation also contains organic-rich layers, with the potential to generate oil. For the majority of samples analysed, the compositional kinetic model predictions indicate that 80% of the hydrocarbons were generated as oil and 20% as gas. The exception is the Lower Cretaceous Echuca Shoals Formation which shows the potential to generate a greater proportion (40%) of gas despite its marine source affinity, due to inertinite dominating the maceral assemblage.     

Basin modeling of the Late Miocene Zeit source rock in the Sudanese portion of Red Sea Basin: Implication for hydrocarbon generation and expulsion history

The Late Miocene Zeit Formation is exposed in the Red Sea Basin of Sudan and represents an important oil-source rock. In this study, five (5) exploratory wells along Red Sea Basin of Sudan are used to model the petroleum generation and expulsion history of the Zeit Formation. Burial/thermal models illustrate that the Red Sea is an extensional rift basin and initially developed during the Late Eocene to Oligocene. Heat flow models show that the present-day heat flow values in the area are between 60 and 109 mW/m². The variation in values of the heat flow can be linked to the raise in the geothermal gradient from margins of the basin towards offshore basin. The offshore basin is an axial area with thick burial depth, which is the principal heat flow source.The paleo-heat flow values of the basin are approximately from 95 to 260 mW/m², increased from Oligocene to Early Pliocene and then decreased exponentially prior to Late Pliocene. This high paleo-heat flow had a considerable effect on the source rock maturation and cooking of the organic matter. The maturity history models indicate that the Zeit Formation source rock passed the late oil-window and converted the oil generated to gas during the Late Miocene.The basin models also indicate that the petroleum was expelled from the Zeit source rock during the Late Miocene (>7 Ma) and it continues to present-day, with transformation ratio of more than 50%. Therefore, the Zeit Formation acts as an effective source rock where significant amounts of petroleum are expected to be generated in the Red Sea Basin.     

Oil migration driven by exhumation of the Canol Formation oil shale: A new conceptual model for the Norman Wells oil field,northwestern Canada

Thermal history, petroleum system, structural, and tectonic constraints are reviewed and integrated in order to derive a new conceptual model for the Norman Wells oil field, and a new play type for tectonically active foreland regions. The thermal history recorded by Devonian rocks suggests that source rocks experienced peak thermal conditions in the Triassic–Jurassic, during which time oil was likely generated. After initial oil generation and expulsion, the Canol Formation oil shale retained a certain fraction of hydrocarbons. The shallow reservoir (650–350 m) is a Devonian carbonate bank overlain by the Canol Formation and resides within a hanging wall block of the Norman Range thrust fault. Both reservoir and source rocks are naturally fractured and have produced high API non-biodegraded oil. Thrust faults in the region formed after the Paleocene, and a structural cross-section of the field shows that the source and reservoir rocks at Norman Wells have been exhumed by over 1 km since then.The key proposition of the exhumation model is that as Canol Formation rocks underwent thrust-driven exhumation, they crossed a ductile–brittle transition zone and dip-oriented fractures formed sympathetic to the thrust fault. The combination of pore overpressure and new dip-directed subvertical fractures liberated oil from the Canol Formation and allowed for up-dip oil migration. Reservoir rocks were similarly fractured and improved permeability enhanced charging and pooling of oil. GPS and seismicity data indicate that strain transfer across the northern Cordillera is a response to accretion of the Yakutat terrane along the northern Pacific margin of North America, which is also the probable driving force for foreland shortening and rock exhumation at Norman Wells.     

Beef veins and thrust detachments in Early Cretaceous source rocks,foothills of Magallanes-Austral Basin,southern Chile and Argentina: Structural evidence for fluid overpressure during hydrocarbon maturation

We describe (1) bedding-parallel veins of fibrous calcite (beef) and (2) thrust detachments, which we believe provide good evidence for fluid overpressure in source rocks for petroleum. Our examples are from the surface or subsurface of the Magallanes-Austral Basin, which lies at the southern tip of South America. There, the best source rocks for petroleum are of Early Cretaceous age. In the central parts of the basin these source rocks have become overmature, but at the eastern edge, onshore and offshore, they are today either immature or in the oil window.In Tierra del Fuego, the foothills of the Andes consist mainly of sedimentary rocks, which have undergone thin-skinned thrusting. In the Vicuña area (Chile), Early Cretaceous source rocks have reached the surface above thrust detachments, which are visible on seismic data and well data. At the surface, we have found calcite beef, containing hydrocarbons (solid and/or fluid), in the Rio Jackson and Vicuña formations, which have reached the wet gas window. In the Rio Gallegos area (Argentina), the source rocks have not reached the surface, but seismic and well data provide good evidence for thin-skinned thrusting above flat-lying detachments in Early Cretaceous source rock, where it is in the early oil window. In contrast, there is little or no deformation where the source rock is still immature. Thus the deformation front coincides with the maturity front. Next to the central parts of the basin, where the source rocks have reached the surface within the Andes proper, they have undergone low-grade metamorphism. Within these source rocks, we have found beef veins, but of quartz, not calcite. To the east, within the foreland basin, seismic and well data provide evidence for a few compressional structures, including thin-skinned detachments in the deeply buried source rock. Finally, in the northern part of the basin (Santa Cruz province, Argentina), where it is shallower, the source rocks have reached the surface in the foothills, above a series of back-thrusts. At Lago San Martín, the source rocks have reached the oil window and they again contain calcite beef.In conclusion, where we have examined Early Cretaceous source rocks at the surface, they contain either calcite beef (if they have reached the late oil window or wet gas window) or quartz beef (if they are overmature). Independent evidence for overpressure, in the form of source-rock detachments, comes from subsurface data, especially at the southern end of the basin, where the source rocks are not overmature and deformation is relatively intense. Thus we argue that hydrocarbon generation has led to overpressure, as a result of chemical compaction and load transfer, or volume changes, or both.     

Thermal maturation, potential source rocks and hydrocarbon generation in Mesozoic rocks, Lougheed Island area, Central Canadian Arctic archipelago

Significant oil and gas accumulations occur in and around Lougheed Island, Arctic Canada, where hydrocarbon prospectivity is controlled by potential source rock distribution and composition. The Middle to Upper Triassic rocks of the Schei Point Group (e.g. Murray Harbour and Hoyle Bay formations) contain a mixture of Types I and II organic matter (Tasmanales marine algae, amorphous fluorescing bituminite). These source rocks are within the oil generation zone and have HI values up to 600 mg HC/g Corg. The younger source rocks of the Lower Jurassic Jameson Bay and the Upper Jurassic Ringnes formations contain mainly gas-prone Type II/III organic matter and are marginally mature. Vitrinite reflectance profiles suggest an effective geothermal gradient essentially similar to the present-day gradient (20 to 30°C/km). Maturation gradients are low, ranging from 0.125 to 0.185 log%Ro/km. Increases in subsidence rate in the Early Cretaceous suggest that the actual heat flow history was variable and has probably diminished from that time. The high deposition rates of the Christopher Formation shales coincide with the main phase of rifting in Aptian-Albian times. Uplift and increased sediment supply in the Maastrichtian resulted in a new sedimentary and tectonic regime, which culminated in the final phase of the Eurekan Orogeny. Burial history models indicate that hydrocarbon generation in the Schei Point Group took place during rifting in Early Cretaceous, long before any Eurekan deformation.     

Petroleum generation and charge history of the northern Dongying Depression,Bohai Bay Basin,China: Insight from integrated fluid inclusion analysis and basin modelling

The petroleum generation and charge history of the northern Dongying Depression, Bohai Bay Basin was investigated using an integrated fluid inclusion analysis workflow and geohistory modelling. One and two-dimensional basin modelling was performed to unravel the oil generation history of the Eocene Shahejie Formation (Es3 and Es4) source rocks based on the reconstruction of the burial, thermal and maturity history. Calibration of the model with thermal maturity and borehole temperature data using a rift basin heat flow model indicates that the upper interval of the Es4 source rocks began to generate oil at around 35 Ma, reached a maturity level of 0.7% R_o at 31–30 Ma and a peak hydrocarbon generation at 24–23 Ma. The lower interval of the Es3 source rocks began to generate oil at around 33–32 Ma and reached a maturity of 0.7% R_o at about 27–26 Ma. Oil generation from the lower Es3 and upper Es4 source rocks occurred in three phases with the first phase from approximately 30–20 Ma; the second phase from approximately 20–5 Ma; and the third phase from 5 Ma to the present day. The first and third phases were the two predominant phases of intense oil generation.Samples from the Es3 and Es4 reservoir intervals in 12 wells at depth intervals between 2677.7 m and 4323.0 m were investigated using an integrated fluid inclusion workflow including petrography, fluorescence spectroscopy and microthermometry to determine the petroleum charge history in the northern Dongying Depression. Abundant oil inclusions with a range of fluorescence colours from near yellow to near blue were observed and were interpreted to represent two episodes of hydrocarbon charge based on the fluid inclusion petrography, fluorescence spectroscopy and microthermometry data. Two episodes of oil charge were determined at 24–20 Ma and 4–3 Ma, respectively with the second episode being the predominant period for the oil accumulation in the northern Dongying Depression. The oil charge occurred during or immediately after the modelled intense oil generation and coincided with a regional uplift and a rapid subsidence, suggesting that the hydrocarbon migration from the already overpressured source rocks may have been triggered by the regional uplift and rapid subsidence. The expelled oil was then charged to the already established traps in the northern Dongying Depression. The proximal locations of the reservoirs to the generative kitchens and the short oil migration distance facilitate the intimate relationship between oil generation, migration and accumulation.     

Oil-oil and oil-source rock correlations in the Alpine Foreland Basin of Austria: Insights from biomarker and stable carbon isotope studies

The Alpine Foreland Basin is a minor oil and moderate gas province in central Europe. In the Austrian part of the Alpine Foreland Basin, oil and minor thermal gas are thought to be predominantly sourced from Lower Oligocene horizons (Schöneck and Eggerding formations). The source rocks are immature where the oil fields are located and enter the oil window at ca. 4 km depth beneath the Alpine nappes indicating long-distance lateral migration. Most important reservoirs are Upper Cretaceous and Eocene basal sandstones.Stable carbon isotope and biomarker ratios of oils from different reservoirs indicate compositional trends in W-E direction which reflect differences in source, depositional environment (facies), and maturity of potential source rocks. Thermal maturity parameters from oils of different fields are only in the western part consistent with northward displacement of immature oils by subsequently generated oils. In the eastern part of the basin different migration pathways must be assumed. The trend in S/(S + R) isomerisation of ααα-C₂₉ steranes versus the αββ (20R)/ααα (20R) C₂₉ steranes ratio from oil samples can be explained by differences in thermal maturation without involving long-distance migration. The results argue for hydrocarbon migration through highly permeable carrier beds or open faults rather than relatively short migration distances from the source. The lateral distance of oil fields to the position of mature source rocks beneath the Alpine nappes in the south suggests minimum migration distances between less than 20 km and more than 50 km.Biomarker compositions of the oils suggest Oligocene shaly to marly successions (i.e. Schoeneck, Dynow, and Eggerding formations) as potential source rocks, taking into account their immature character. Best matches are obtained between the oils and units a/b (marly shale) and c (black shale) of the “normal” Schöneck Formation, as well as with the so-called “Oberhofen Facies”. Results from open system pyrolysis-gas chromatography of potential source rocks indicate slightly higher sulphur content of the resulting pyrolysate from unit b. The enhanced dibenzothiophene/phenanthrene ratios of oils from the western part of the basin would be consistent with a higher contribution of unit b to hydrocarbon expulsion in this area. Differences in the relative contribution of sedimentary units to oil generation are inherited from thickness variations of respective units in the overthrusted sediments. The observed trend towards lighter δ¹³C values of hydrocarbon fractions from oil fields in a W-E direction are consistent with lower δ¹³C values of organic matter in unit c.     

珠江口盆地文昌A凹陷油气差异分布特征

在烃源岩分布特征、有机质丰度、类型和成熟度分析的基础上,运用含油气盆地数值模拟技术,定量恢复了烃源岩热成熟演化史,探讨了油气差异分布特征。研究表明,文昌A凹陷各层系烃源岩分布广,厚度大,有机质丰度高;有机质类型文昌组偏Ⅱ1型,恩平组偏Ⅲ型,二者现今多处于高成熟—过成熟阶段。凹陷内烃源岩成熟时间早(文昌组约45.5Ma),现今成熟度高,以干气生成为主;凹陷边缘烃源岩成熟时间较晚(文昌组约30.0Ma),现今成熟度相对较低,以石油生成为主。凹陷现今油气差异分布的格局受制于有机质类型差异和热演化史不同,且下一步油气勘探方向,凹陷内以天然气为主,凹陷边缘以石油为主。     

Potential for gas hydrate formation at the northwest New Zealand shelf margin - New insights from seismic reflection data and petroleum systems modelling

In this study we provide evidence for methane hydrates in the Taranaki Basin, occurring a considerable distance from New Zealand's convergent margins, where they are well documented. We describe and reconstruct a unique example of gas migration and leakage at the edge of the continental shelf, linking shallow gas hydrate occurrence to a deeper petroleum system. The Taranaki Basin is a well investigated petroleum province with numerous fields producing oil and gas. Industry standard seismic reflection data show amplitude anomalies that are here interpreted as discontinuous BSRs, locally mimicking the channelized sea-floor and pinching out up-slope. Strong reverse polarity anomalies indicate the presence of gas pockets and gas-charged sediments. PetroMod™ petroleum systems modelling predicts that the gas is sourced from elevated microbial gas generation in the thick slope sediment succession with additional migration of thermogenic gas from buried Cretaceous petroleum source rocks. Cretaceous–Paleogene extensional faults underneath the present-day slope are interpreted to provide pathways for focussed gas migration and leakage, which may explain two dry petroleum wells drilled at the Taranaki shelf margin. PetroMod™ modelling predicts concentrated gas hydrate formation on the Taranaki continental slope consistent with the anomalies observed in the seismic data. We propose that a semi-continuous hydrate layer is present in the down-dip wall of incised canyons. Canyon incision is interpreted to cause the base of gas hydrate stability to bulge downward and thereby trap gas migrating up-slope in permeable beds due to the permeability decrease caused by hydrate formation in the pore space. Elsewhere, hydrate occurrence is likely patchy and may be controlled by focussed leakage of thermogenic gas. The proposed presence of hydrates in slope sediments in Taranaki Basin likely affects the stability of the Taranaki shelf margin. While hydrate presence can be a drilling hazard for oil and gas exploration, the proposed presence of gas hydrates opens up a new frontier for exploration of hydrates as an energy source.     

四川盆地雷四3亚段油气勘探方向

近年来,中石油和中石化在四川盆地雷口坡组雷四³亚段的勘探陆续取得重要进展,展示了良好的勘探前景。笔者结合新钻探井和最新研究成果,从地层、沉积相、烃源岩、储层和成藏等多方面采用烃源对比、埋藏史及烃源岩热演化史、包裹体测温等方法对四川盆地雷四³亚段的含油气地质条件进行了进一步分析,总结了其油气成藏特征,提出了有利勘探区带,以期有助于拓展四川盆地雷口坡组的勘探领域。研究结果表明:雷四³亚段天然气以雷口坡组和须家河组烃源岩混合来源气为主;储集空间以粒间溶孔、晶间溶孔为主,属低孔低渗储层;雷四³亚段气藏为2期成藏,烃源岩于中、晚侏罗世进入生烃高峰;雷四³亚段具有构造和构造-岩性地层2种气藏类型,龙门山山前断褶带为构造气藏的有利勘探区,新津-邛崃斜坡带与梓潼-盐亭斜坡带是构造-岩性地层气藏的有利勘探区。     

Source rocks and related petroleum systems of the Chelif Basin, (western Tellian domain,north Algeria)

In the Chelif basin, the geochemical characterization reveals that the Upper Cretaceous and Messinian shales have a high generation potential. The former exhibits fair to good TOC values ranging from 0.5 to 1.2% with a max. of 7%. The Messinian series show TOC values comprised between 0.5 and 2.3% and a high hydrogen index (HI) with values up to 566 mg HC/g TOC. Based on petroleum geochemistry (CPLC and CPGC) technics, the oil-to source correlation shows that the oil of the Tliouanet field display the same signature as extracts from the Upper Cretaceous source rocks (Cenomanian to Campanian). In contrast, oil from the Ain Zeft field contains oleanane, and could thus have been sourced by the Messinian black shale or older Cenozoic series. Two petroleum systems are distinguished: Cretaceous (source rock) – middle to upper Miocene (reservoirs) and Messinian (source rock)/Messinian (reservoirs). Overall, the distribution of Cretaceous-sourced oil in the south, directly connected with the surface trace of the main border fault of the Neogene pull-apart basin, rather suggests a dismigration from deeper reservoirs located in the parautochthonous subthrust units or in the underthrust foreland, rather than from the Tellian allochthon itself (the latter being mainly made up of tectonic mélange at the base, reworking blocks and slivers of Upper Cretaceous black shale and Lower Miocene clastics). Conversely, the occurrence of Cenozoic-sourced oils in the north suggests that the Neogene depocenters of the Chelif thrust-top pull-apart basin reached locally the oil window, and therefore account for a local oil kitchen zone. In spite of their limited extension, allochthonous Upper cretaceous Tellian formations still conceal potential source rock layers, particularly around the Dahra Mountains and the Tliouanet field. Additionally they are also recognized by the W11 well in the western part of the basin (Tahamda). The results of the thermal modelling of the same well shows that there is generation and migration of oil from this source rock level even at recent times (since 8 Ma), coevally with the Plio-Quaternary traps formation. Therefore, there is a possibility of an in-situ oil migration and accumulation, even from Tellian Cretaceous units, to the recent structures, like in the Sedra structure. However, the oil remigration from deep early accumulations into the Miocene reservoirs is the most favourable case in terms of hydrocarbon potential of the Chelif basin.     

Petroleum retention in the Mandal Formation,Central Graben,Norway

Upper Jurassic organic matter-rich, marine shales of the Mandal Formation have charged major petroleum accumulations in the North Sea Central Graben including the giant Ekofisk field which straddles the graben axis. Recent exploration of marginal basin positions such as the Mandal High area or the Søgne Basin has been less successful, raising the question as to whether charging is an issue, possibly related to high thermal stability of the source organic matter or delayed expulsion from source to carrier.The Mandal Formation is in part a very prolific source rock containing mainly Type II organic matter with <12 wt.-% TOC and HI < 645 mg HC/g TOC but Type III-influenced organofacies are also present. The formation is therefore to varying degrees heterogeneous. Here we show, using geochemical mass balance modelling, that the petroleum expulsion efficiency of the Mandal Formation is relatively low as compared to the Upper Jurassic Draupne Formation, the major source rock in the Viking Graben system. Using maturity series of different initial source quality from structurally distinct regions and encompassing depositional environments from proximal to distal facies, we have examined the relationship between free hydrocarbon retention and organic matter structure. The aromaticity of the original and matured petroleum precursors in the Mandal source rock plays a major role in its gas retention capacity as cross-linked monoaromatic rings act on the outer surface of kerogen as sorptive sites. However, oil retention is a function of both kerogen and involatile bitumen compositions. Slight variations in total petroleum retention capacities within the same kerogen yields suggest that texture of organic matter (e.g. organic porosity) could play a role as well.