Pressure cells and pressure seals in the UK Central Graben

The Central Graben of the North Sea is characterised by high levels of overpressure (up to 40 MPa overpressure at 4500 m depth). We present pressure data for Cenozoic and Mesozoic reservoirs. Palaeocene sandstones control pressures in Tertiary mudstones and Cretaceous Chalk by acting as a regional ‘drain’. We divide the Jurassic into 18 pressure cells. The rift structure of the Graben controls the magnitude of pressure in each cell. Lateral hydraulic communication exists over 10 km distance between deeply-buried terraces (> 5000 m depth) and shallow structural highs (< 4500 m depth). Lateral communication increases pressure in the structurally-elevated sandstones to the minimum stress. This dynamic process produces zones of vertical fluid flow on the Forties-Montrose High, termed Leak Points. Vertical flow at Leak Points produces a 20 MWm⁻² heat flow anomaly and controls hydrocarbon retention. Leak Points are water-wet, while deep terraces in hydraulic communication with Leak Points are condensate-bearing. The Kimmeridge Clay Fm. forms the pressure seal in deep terraces.     

Mechanisms of petroleum accumulation in the Bozhong sub-basin, Bohai Bay Basin, China. Part 1: Origin and occurrence of crude oils

The origin of the fourteen major oil fields in the Bozhong sub-basin, Bohai Bay basin was studied based on the results of Rock-Eval pyrolysis on more than 700 samples and biomarker analysis on 61 source rock samples and 87 oil samples. The three possible source rock intervals have different biomarker assemblages and were deposited in different environments. The third member of the Oligocene Dongying Formation (E₃d₃, 32.8–30.3 Ma in age) is characterized mainly by high C₁₉/C₂₃ tricyclic terpane (>0.75), high C₂₄ tetracyclic terpane/C₂₆ tricyclic terpane (>2.5), low gammacerane/αβ C₃₀ hopane (<0.15) and low 4-methyl steranes/ΣC₂₉ steranes (<0.15) ratios, and was deposited in sub-oxic to anoxic environments with significant terrigenous organic matter input. The first (E₂s₁, 35.8–32.8 Ma) and third (E₂s₃, 43.0–38.0 Ma) members of the Eocene Shahejie Formation have low C₁₉/C₂₃ tricyclic terpane and low C₂₄ tetracyclic terpane/C₂₆ tricyclic terpane ratios and were deposited in anoxic environments with minor terrestrial organic matter input, but have different abundances of 4-methyl steranes and gammacerane. The hydrocarbon-generating potential and biomarker associations of these three source rock intervals were controlled by tectonic evolution of the sub-basin and climate changes. Three oil families derived from E₂s₃, E₂s₁ and E₃d, respectively, and three types of mixed oils have been identified. All large oil fields in the Bozhong sub-basin display considerable heterogeneities in biomarker compositions and originated from more than one source rock interval, which suggests that mixing of oils derived from multiple source rock intervals or multiple generative kitchens, and/or focusing of oils originated from a large area of a generative kitchen, is essential for the formation of large oil fields in the Bozhong sub-basin. E₂s₃- and E₂s₁-derived oils experienced relatively long-distance lateral migration and accumulated in traps away from the generative kitchen. E₃d₃-derived oils had migrated short distances and accumulated in traps closer to the generative kitchen. Such a petroleum distribution pattern has important implications for future exploration. There is considerable exploration potential for Dongying-derived oils in the Bozhong sub-basin, and traps close to or within the generative kitchens have better chance to contain oils generated from the Dongying Formation.     

Distribution of the Neogene Utsira Sand and the succeeding deposits in the Viking Graben area, North Sea

The sandy quartzose parts of the Utsira Formation, the Middle Miocene to mid Pliocene Utsira Sand, extends north–south along the Viking Graben near the UK/Norwegian median line for more than 450 km and 75–130 km east–west. The Utsira Sand is located in basin-restricted seismic depocentres, east of and below prograding sandy units from the Shetland Platform area with Hutton Sands. The Utsira Sand reaches thicknesses up to ca. 300 m in the southern depocentre and 200 m in the two northern depocentres with sedimentation rates up to 2–4 cm/ka. Succeeding Plio–Pleistocene is divided into seismic units, including Base Upper Pliocene, Shale Drape, Prograding Complex and Pleistocene. The units mainly consist of clay, but locally minor sands occur, especially at toes of prograding clinoforms (bottom-set sands) and in the Pleistocene parts, and the total thickness covering the Utsira Sand is in most places more than 800 m, but thins towards the margins.     

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.     

Marine hydrocarbon source rocks of the Upper Permian Longtan Formation and their contribution to gas accumulation in the northeastern Sichuan Basin,southwest China

Identification of the main hydrocarbon source rocks of the large Puguang gas field (northeastern Sichuan Basin, southwest China) has been the subject of much discussion in recent years. A key aspect has been the lack of a comprehensive understanding of the development of hydrocarbon source rocks of the Upper Permian Longtan Formation, which had been thought to contain mainly coal seams and thick carbonate layers. In this paper, based on geological data from more than ten wells and outcrops and their related mineralogy and geochemistry, we investigated the depositional environment and main factors controlling organic matter enrichment in the Longtan Formation. We propose a model which combines information on the geological environment and biological changes over time. In the model, organic matter from prolific phytoplankton blooms was deposited in quiescent platform interior sags with rising sea-levels. During the Longtan period, the area from Bazhong to Dazhou was a platform interior sag with relatively deep water and a closed environment, which was controlled by multiple factors including syngenetic fault settling, isolation of submarine uplifts and rising sea-levels leading to water column stratification. Although the bottom water was anoxic, the phytoplankton were able to bloom in the well-lit upper euphotic zone thus giving rise to a set of sapropelic black shales and marlstones containing mostly algal organic matter with minor terrestrial contributions. As a consequence, these rocks have a high hydrocarbon generation potentials and can be classified as high-quality source rocks. The area from Bazhong to Dazhou is a center of hydrocarbon generation, being the main source of reservoired paleo-oils and presently discovered as pyrobitumen in the Puguang gas field. The identification of these source rocks is very important to guide future petroleum exploration in the northeastern Sichuan Basin.     

Calibration of the mudrock compaction curve by eliminating the effect of organic matter in organic-rich shales: Application to the southern Ordos Basin,China

The mudrock log-derived compaction curve is a significant tool for investigating the primary migration of hydrocarbon, predicting fluid overpressure, estimating formation erosion thicknesses and restoring the buried history and paleo-structure of a basin. However, the presence of kerogen in organic-rich shales can create typically high logging values of the acoustic transit time. Thus, the abnormally high values of the acoustic transit time for organic-rich rocks may not truly reflect the porosity variations of subsurface rocks, leading to great uncertainties in the understanding of the mudstone compaction and a certain amount of error in the abnormal fluid pressure estimation when using the mudrock log-derived compaction curve. Therefore, it is necessary to recalibrate the mudstone compaction curve by eliminating the increment of the acoustic transit time caused by the kerogen content of organic-rich mudstones. Taking the southwest Ordos Basin as an example, this paper presents a new equivalent volume model based on the composition of organic-rich shale in which the kerogen content is also considered. Based on the quantitative relationship between the rock composition and the acoustic transit time, a quantitative formula for calculating the acoustic transit time increment caused by the kerogen is derived. This formula shows that the increment depends not only on the organic content but also on the occurrence state, pore size, pore fluid composition and other factors. X-ray diffraction (XRD) data were used to determine the main mineral composition of the mudstone and to calculate the acoustic transit time of the rock skeleton. Then, the mudstone compaction curve in the Zhenjing area was calibrated by combining the measured porosity and total organic carbon (TOC) of the mudstone based on the correction formula. The compaction characteristics varied significantly between before and after the calibration. The slope of the normal compaction trend (NCT) line decreased by 30–55%, and the acoustic transit time deviation from the NCT in the undercompaction interval decreased significantly. The overpressure at the maximum burial depth estimated by the equivalent depth method is in better agreement with the results obtained by numerical simulation after the calibration, and the porosity determined from the well log after the calibration is also closer to the true measured value. The method proposed in this paper is of great significance for improving the reliability and accuracy of compaction research on organic-rich mudstones, especially for the accurate estimation of abnormal pressure in the source rock layer. Additionally, it can be used as an effective reference for mudstone compaction studies in similar geological settings areas or basins.     

Organic geochemistry and source potential of the lacustrine shales of the Upper Triassic - Lower Jurassic Kap Stewart Formation, East Greenland

The Upper Triassic — Lower Jurassic Kap Stewart Formation (Jameson Land, East Greenland) has been studied by a combination of sedimentological and organic geochemical methods (LECO/Rock Eval, sulphur, gas chromatography) in order to assess the hydrocarbon source potential of the abundant and extensive lacustrine shale intervals present in the formation.The organic matter in the shales is a mixture of algal and higher plant remains (type I and III kerogen). An organic assemblage dominated by algal material, having a rich oil potential, occurs in an interval approximately 10–15 m thick in the uppermost part of the formation. This interval has an organic carbon content up to 10% and Hydrogen Index values up to 700. The interval is consistently traceable along the exposed margins and the central part of the basin. The deposition of the uppermost shale interval coincided with the largest expansion of the lake, during a period with a stratified water column and anoxic bottom-water conditions.Locally the rocks exposed are thermally postmature due to the thermal influence of dolerite sills which intruded the Kap Stewart Formation in Tertiary time. However, the organic-rich shale interval is beyond the influence of the sills and indicates a maturity prior to or in the early stages of oil generation.Calculations of the generative potential of the lacustrine source rocks suggest that significant amounts of petroleum may have been generated in those sediments which have undergone sufficient burial in the southern and central part of the basin. Here, the contemporaneously deposited delta front and barrier island sandstones can thus be considered as potential targets for future hydrocarbon exploration. This type of play may also be of importance in other North Atlantic basins with a similar basin history.     

Source rock characteristics and hydrocarbon generation modelling of Upper Cretaceous Mukalla Formation in the Jiza-Qamar Basin,Eastern Yemen

The Upper Cretaceous Mukalla coals and other organic-rich sediments which are widely exposed in the Jiza-Qamar Basin and believed to be a major source rocks, were analysed using organic geochemistry and petrology. The total organic carbon (TOC) contents of the Mukalla source rocks range from 0.72 to 79.90% with an average TOC value of 21.50%. The coals and coaly shale sediments are relatively higher in organic richness, consistent with source rocks generative potential. The samples analysed have vitrinite reflectance in the range of 0.84–1.10 %Ro and pyrolysis T_max in the range of 432–454 °C indicate that the Mukalla source rocks contain mature to late mature organic matter. Good oil-generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices (250–449 mg HC/g TOC). This is supported by their significant amounts of oil-liptinite macerals are present in these coals and coaly shale sediments and Py-GC (S₂) pyrograms with n-alkane/alkene doublets extending beyond nC₃₀. The shales are dominated by Type III kerogen (HI < 200 mg HC/g TOC), and are thus considered to be gas-prone.One-dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the Mukalla source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial/thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the Mukalla source rocks. Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature data indicates that the present-day heat flow in the Jiza-Qamar Basin varies from 45.0 mW/m² to 70.0 mW/m² and the paleo-heat flow increased from 80 Ma to 25 Ma, reached a peak heat-flow values of approximately 70.0 mW/m² at 25 Ma and then decreased exponentially from 25 Ma to present-day. The peak paleo-heat flow is explained by the Gulf of Aden and Red Sea Tertiary rifting during Oligocene-Middle Miocene, which has a considerable influence on the thermal maturity of the Mukalla source rocks. The source rocks of the Mukalla Formation are presently in a stage of oil and condensate generation with maturity from 0.50% to 1.10% Ro. Oil generation (0.5% Ro) in the Mukalla source rocks began from about 61 Ma to 54 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 25 Ma to 20 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Mukalla source rocks began from 15 Ma to present-day.     

Effects of oil expulsion and pressure on nanopore development in highly mature shale: Evidence from a pyrolysis study of the Eocene Maoming oil shale,south China

The influence of oil-expulsion efficiency on nanopore development in highly mature shale was investigated by using anhydrous pyrolysis (425–600 °C) on solvent-extracted and non-extracted shales at a pressure of 50 MPa. Additional pyrolysis studies were conducted using non-extracted shales at pressures of 25 and 80 MPa to further characterize the impact of pressure on pore evolution at high maturity. The pore structures of the original shale and relevant artificially matured samples after pyrolysis were characterized by using low-pressure nitrogen and carbon-dioxide adsorption techniques, and gas yields during pyrolysis were measured. The results show that oil-expulsion efficiency can strongly influence gas generation and nanopore development in highly mature shales, as bitumen remained in shales with low oil expulsion efficiency significantly promotes gaseous hydrocarbon generation and nanopore (diameter < 10 nm) development. The evolution of micropores and fine mesopores at high maturity can be divided into two main stages: Stage I, corresponding to wet gas generation (EasyRo 1.2%–2.4%), and Stage II, corresponding to dry gas generation (EasyRo 2.4%–4.5%). For shales with low oil expulsion efficiency, nanopore (diameter < 10 nm) evolution increases rapidly in Stage I, whereas slowly in Stage II, and such difference between two stages may be attributed to the changes of the organic matter (OM)’s mechanical properties. Comparatively, for shales with high oil expulsion efficiency, the evolution grows slightly in Stage I, not as rapidly as shales with low efficiency, and decays in Stage II. The different pore evolution behaviors of these two types of shales are attributed to the contribution of bitumen. However, the evolution of medium–coarse mesopores and macropores (diameter >10 nm) remains flat at high maturation. In addition, high pressure can promote the development of micropores and fine mesopores in highly mature shales.     

Petroleum generation characteristics of heterogeneous source rock from Chia Gara formation in the Kurdistan region,northern Iraq as inferred by bulk and quantitative pyrolysis techniques

This study is the first attempt which provides information regarding the bulk and quantitative pyrolysis results of the Chia Gara Formation from the Kurdistan region, northern Iraq. Ten representative early-mature to mature samples from the Chia Gara Formation were investigated for TOC contents, Rock Eval pyrolysis, pyrolysis-GC and bulk kinetic parameters. These analyses were used to characterize the petroleum generated during thermal maturation of the Chia Gara source rock and to clarify the quantity of the organic matter and its effect on the timing of petroleum generation.Pyrolysis HI data identified two organic facies with different petroleum generation characteristics; Type II–III kerogen with HI values of >250 mg HC/g TOC, and Type III kerogen with HI values < 100 mg HC/g TOC. These types of kerogen can generate liquid HCs and gas. This is supported by the products of pyrolysis–gas chromatography (Py–GC) analysis of the extracted rock samples. Pyrolysis products show a dominance of a marine organic matter with variable contributions from terrestrial organic matter (Types II–III and III kerogen), and produces mainly paraffinic-naphthenic-aromatic low wax oils with condensate and gas.Bulk kinetic analysis of the Chia Gara source rock indicates a heterogeneous organic matter assemblage, typical of restricted marine environments in general. The activation energy distributions reveal relatively broad and high values, ranging from 40 to 64 kcal/mol with pre-exponential factors varying from 2.2835 E+12/sec to 4.0920 E+13/sec. The predicted petroleum formation temperature of onset (TR 10%) temperatures ranges from 110 to 135 °C, and peak generation temperatures (geological T_max) between 137 °C and 152 °C. The peak generation temperatures reach a transformation ratio in the range of 42–50% TR, thus the Chia Gara source rock could have generated and expelled significant quantities of petroleum hydrocarbons in the Kurdistan of Iraq.     

Palynofacies,organic geochemistry and depositional environment of the Tartan Formation (Late Paleocene), a potential source rock in the Great South Basin,New Zealand

Detailed palynofacies analysis of sidewall core samples taken from below, within and above the Tartan Formation (Thanetian, Late Paleocene, 58.7–55.8 Ma), a potential source rock in the epeiric Great South Basin, shows that the formation is characterised by very high percentages of degraded brown phytoclasts, rare marine algae and amorphous organic matter and thereby represents a mix of terrestrial and marine kerogen. The results indicate that the formation was deposited in a marginally marine (hyposaline), proximal environment under bottom conditions that varied from anoxic to oxic along a nearshore–offshore transect. Samples from the upper part of the underlying Wickliffe Formation indicate deposition in a marginal to normal marine, proximal environment under anoxic to oxic bottom environments. The lower part of the overlying Laing Formation was deposited in an open marine, relatively distal setting under anoxic to oxic bottom environments.