Diagenetic history of tight sandstones and gas entrapment in the Yulin Gas Field in the central area of the Ordos Basin,China

The Ordos Basin is a large cratonic basin with an area of 250,000 km² in central China. Upper Paleozoic coals and shales serve as gas source rocks with peak generation and migration at the end of the early Cretaceous. Recent exploration has verified the huge gas potential in the “basin-centered gas accumulation system” (BCGAS). However, the mechanism for the gas accumulation is controversial. With an integrated approach of thin-section petrography, ultra-violet fluorescence microscopy, fluid inclusion microthermometry, Raman microspectrometry, scanning electron microscopy, and X-ray diffractometry, we identified diagenetic trapping and evaluated the diagenetic history of sandstone reservoirs in the Yulin Gas Field in the central area, where structural, stratigraphic and/or sedimentary lithologic traps have not been found. It was revealed that three phases of diagenesis and hydrocarbon charging occurred, respectively, in the late Triassic, late Jurassic and at the end of the early Cretaceous. In the first two phases, acidic water entered the reservoir and caused dissolution and cementation, resulting in porosity increase. However, further subsidence and diagenesis, including compaction and cementation, markedly reduced the pore space. At the end of the early Cretaceous, the bulk of the gas migrated into the tight reservoirs, and the BCGAS trap was formed. In the updip portion of this system, cementation continued to occur due to low gas saturation and has provided effective seals to retain gas for a longer period of time than water block in the BCGAS. The mechanism for the gas entrapment was changed from water block by capillary pressure in the BCGAS to diagenetic sealing. The diagenetic seals in the updip portion of the sand body were formed after gas charging, which indicates that there is a large hydrocarbon exploration potential at the basin-centered area.     

Hydrocarbon migration and accumulation of the Suqiao buried-hill zone in Wen'an Slope,Jizhong Subbasin,Bohai Bay Basin,China

The hydrocarbon migration and accumulation of the Suqiao deep buried-hill zone, in the Jizhong Subbasin, the Bohai Bay Basin, eastern China, was investigated from the perspective of paleo-fluid evidence by using fluid inclusions, quantitative fluorescence techniques (QGF), total scanning fluorescence method (TSF) and organic geochemical analysis. Results show that the current condensate oil-gas reservoirs in the study area once were paleo-oil reservoirs. In addition, the reservoirs have experienced at least two stages of hydrocarbon charge from different sources and/or maturities. During the deposition of the Oligocene Dongying Formation (Ed), the deep Ordovician reservoirs were first charged by mature oils sourced from the lacustrine shale source rocks in the fourth member of Shahejie and Kongdian Formations (Es₄+Ek), and then adjusted at the end of Ed period subsequently by virtue of the tectonic movement. Since the deposition of the Neogene Minghuazhen Formation (Nm), the reservoirs were mainly charged by the gas that consisted of moderate to high-maturity condensate and wet gas sourced from the Es₄+Ek lacustrine shale source rocks and mature coal-derived gas sourced from the Carboniferous-Permian (C-P) coal-bearing source rocks. Meanwhile, the early charged oil was subjected to gas flushing and deasphalting by the late intrusion of gas. The widely distributed hydrocarbon inclusions, the higher QGF Index, and FOI (the frequency of oil inclusions) values in both gas-oil and water zone, are indicative of early oil charge. In addition, combined with the homogenization temperatures of the fluid inclusions (<160 °C) and the existence of solid-bitumen bearing inclusions, significant loss of the n-alkanes with low carbon numbers, enrichments of heavier components in crude oils, and the precipitation of asphaltene in the residual pores suggest that gas flushing may have played an important role in the reservoir formation.     

Petroleum accumulation in the deeply buried reservoirs in the northern Dongying Depression,Bohai Bay Basin,China: New insights from fluid inclusions,natural gas geochemistry,and 1-D basin modeling

The deeply buried reservoirs (DBRs) from the Lijin, Shengtuo and Minfeng areas in the northern Dongying Depression of the Bohai Bay Basin, China exhibit various petroleum types (black oil-gas condensates) and pressure systems (normal pressure-overpressure) with high reservoir temperatures (154–185 °C). The pressure-volume-temperature-composition (PVTX) evolution of petroleum and the processes of petroleum accumulation were reconstructed using integrated data from fluid inclusions, stable carbon isotope data of natural gas and one-dimensional basin modeling to trace the petroleum accumulation histories.The results suggest that (1) the gas condensates in the Lijin area originated from the thermal cracking of highly mature kerogen in deeper formations. Two episodes of gas condensate charging, which were evidenced by the trapping of non-fluorescent gas condensate inclusions, occurred between 29-25.5 Ma and 8.6–5.0 Ma with strong overpressure (pressure coefficient, P_c = 1.68–1.70), resulting in the greatest contribution to the present-day gas condensate accumulation; (2) the early yellow fluorescent oil charge was responsible for the present-day black oil accumulation in well T764, while the late blue-white oil charge together with the latest kerogen cracked gas injection resulted in the present-day volatile oil accumulation in well T765; and (3) the various fluorescent colors (yellow, blue-white and blue) and the degree of bubble filling (F_v) (2.3–72.5%) of the oil inclusions in the Minfeng area show a wide range of thermal maturity (API gravity ranges from 30 to 50°), representing the charging of black oil to gas condensates. The presence of abundant blue-white fluorescent oil inclusions with high Grain-obtaining Oil Inclusion (GOI) values (35.8%, usually >5% in oil reservoirs) indicate that a paleo-oil accumulation with an approximate API gravity of 39–40° could have occurred before 25 Ma, and gas from oil cracking in deeper formations was injected into the paleo-oil reservoir from 2.8 Ma to 0 Ma, resulting in the present-day gas condensate oil accumulation. This oil and gas accumulation model results in three oil and gas distribution zones: 1) normal oil reservoirs at relatively shallow depth; 2) gas condensate reservoirs that originated from the mixture of oil cracking gas with a paleo-oil reservoir at intermediate depth; and 3) oil-cracked gas reservoirs at deeper depth.The retardation of organic matter maturation and oil cracking by high overpressure could have played an important role in the distribution of different origins of gas condensate accumulations in the Lijin and Minfeng areas. The application of oil and gas accumulation models in this study is not limited to the Dongying Depression and can be applied to other overpressured rift basins.     

Alteration and multi-stage accumulation of oil and gas in the Ordovician of the Tabei Uplift,Tarim Basin,NW China: Implications for genetic origin of the diverse hydrocarbons

The Ordovician is the most important exploration target in the Tabei Uplift of the Tarim Basin, which contains a range of petroleum types including solid bitumen, heavy oil, light oil, condensate, wet gas and dry gas. The density of the black oils ranges from 0.81 g/cm³ to 1.01 g/cm³ (20 °C) and gas oil ratio (GOR) ranges from 4 m³/m³ to 9300 m³/m³. Oil-source correlations established that most of the oils were derived from the Mid-Upper Ordovician marine shale and carbonate and that the difference in oil properties is mainly attributed to hydrocarbon alteration and multi-stage accumulation. In the Tabei Uplift, there were three main periods of hydrocarbon accumulation in the late Caledonian stage (ca. 450–430 Ma), late Hercynian stage (ca. 293–255 Ma) and the late Himalayan stage (ca. 12–2 Ma). The oil charging events mainly occurred in the late Caledonian and late Hercynian stage, while gas charging occurred in the late Hercynian stage. During the late Caledonian stage, petroleum charged the reservoirs lying east of the uplift. However, due to a crustal uplifting episode in the early Hercynian (ca. 386–372 Ma), most of the hydrocarbons were transformed by processes such as biodegradation, resulting in residual solid bitumen in the fractures of the reservoirs. During the late Hercynian Stage, a major episode of oil charging into Ordovician reservoirs took place. Subsequent crustal uplift and severe alteration by biodegradation in the west-central Basin resulted in heavy oil formation. Since the late Himalayan stage when rapid subsidence of the crust occurred, the oil residing in reservoirs was exposed to high temperature cracking conditions resulting in the production of gas and charged from the southeast further altering the pre-existing oils in the eastern reservoirs. A suite of representative samples of various crude oils including condensates, lights oils and heavy oils have been collected for detailed analysis to investigate the mechanism of formation. Based on the research it was concluded that the diversity of hydrocarbon physical and chemical properties in the Tabei Uplift was mainly attributable to the processes of biodegradation and gas washing. The understanding of the processes is very helpful to predict the spatial distribution of hydrocarbon in the Tabei Uplift and provides a reference case study for other areas.     

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.     

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.     

Origin of the hydrocarbon gases carbon dioxide and hydrogen sulfide in Dodan Field (SE-Turkey)

Gas occurrences consisting of carbon dioxide (CO₂), hydrogen sulfide (H₂S), and hydrocarbon (HC) gases and oil within the Dodan Field in southeastern Turkey are located in Cretaceous carbonate reservoir rocks in the Garzan and Mardin Formations. The aim of this study was to determine gas composition and to define the origin of gases in Dodan Field. For this purpose, gas samples were analyzed for their molecular and isotopic composition. The isotopic composition of CO₂, with values of −1.5‰ and −2.8‰, suggested abiogenic origin from limestone. δ³⁴S values of H₂S ranged from +11.9 to +13.4‰. H₂S is most likely formed from thermochemical sulfate reduction (TSR) and bacterial sulfate reduction (BSR) within the Bakuk Formation. The Bakuk Formation is composed of a dolomite dominated carbonate succession also containing anhydrite. TSR may occur within an evaporitic environment at temperatures of approximately 120–145 °C. Basin modeling revealed that these temperatures were reached within the Bakuk Formation at 10 Ma. Furthermore, sulfate reducing bacteria were found in oil–water phase samples from Dodan Field. As a result, the H₂S in Dodan Field can be considered to have formed by BSR and TSR.As indicated by their isotopic composition, HC gases are of thermogenic origin and were generated within the Upper Permian Kas and Gomaniibrik Formations. As indicated by the heavier isotopic composition of methane and ethane, HC gases were later altered by TSR. Based on our results, the Dodan gas field may have formed as a result of the interaction of the following processes during the last 7–8 Ma: 1) thermogenic gas generation in Permian source rocks, 2) the formation of thrust faults, 3) the lateral-up dip migration of HC-gases due to thrust faults from the Kas Formation into the Bakuk Formation, 4) the formation of H₂S and CO₂ by TSR within the Bakuk Formation, 5) the vertical migration of gases into reservoirs through the thrust fault, and 6) lateral-up dip migration within reservoir rocks toward the Dodan structure.     

Hydrocarbon accumulation model for Neogene traps in the Chengdao area,Bohai Bay Basin,China

Chengdao is an offshore area in the Bohai Bay Basin that contains approximately 25.7 × 10⁸ bbl of oil and gas reserves within the sandstone reservoirs in Neogene strata. However, previous predictions of hydrocarbon accumulation in Neogene traps are inaccurate, resulting in a current failure rate of 50% when drilling for hydrocarbons in this area. To build an improved exploration model for Neogene traps, we select 92 traps from Neogene strata in the Chengdao area to quantify the filling degree, which is an indicator of hydrocarbon accumulation efficiency. The quantified filling degree is based on actual geological and exploration data and differs significantly among various trap types. The filling degree of traps also varies significantly with their structural locations and decreases generally from the northwest to the southeast along the Chengbei Fault zone. Vertically, the filling degree is highly heterogeneous, initially increasing from the bottom to the middle of Neogene strata and then decreasing towards the top of the strata. These Neogene hydrocarbon reservoirs are sourced from the Paleogene, and as they lay vertically away from the source rocks, their hydrocarbon enrichment is constrained largely by hydrocarbon migration distance and vertical migration pathways. The sealing capacity of faults and cap rocks, sandbody orientation and reservoir sedimentary facies determine the maximum column height, which in turn affects the amount of hydrocarbon accumulation within these traps. A scatter plot analysis of individual controls and volumetric filling for each trap type is compiled using multivariate linear regression analysis to quantify controls and the dominant control of hydrocarbon accumulation is determined.     

Geological roles of the siltstones in tight oil play

Understanding the hydrocarbon accumulation pattern in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil accumulation are mostly concerned with self-generation or from source to reservoir rock over short distances. However, the Lucaogou tight oil in Jimusar Sag of Junggar Basin shows transitional feature in between. The Lucaogou Formation comprises fine-grain sedimentary rocks characterized by thin laminations and frequently alternating beds. The Lucaogou tight silt/fine sandstones are poorly sorted. Dissolved pores are the primary pore spaces, with average porosity of 9.20%. Although the TOC of most silt/fine sandstones after Soxhlet extraction is lower than that before extraction, they show that the Lucaogou siltstones in the area of study have fair to good hydrocarbon generation potential (average TOC of 1.19%, average S₂ of 4.33 mg/g), while fine sandstones are relatively weak in terms of hydrocarbon generation (average TOC of 0.4%, average S₂ of 0.78 mg/g). The hydrocarbon generation amount of siltstones, which was calculated according to basin modeling transformation ratio combined with original TOC based on source rock parameters, occupies 16%–72% of oil retention amount. Although siltstones cannot produce the entire oil reserve, they certainly provide part of them. Grain size is negatively correlated with organic matter content in the Lucaogou silt/fine sandstones. Fine grain sediments are characterized by lower deposition rate, stronger adsorption capacity and oxidation resistance, which are favorable for formation of high quality source rocks. Low energy depositional environment is the primary reason for the formation of siltstones containing organic matter. Positive correlation between organic matter content and clay content in Lucaogou siltstones supports this view point. Lucaogou siltstones appear to be effective reservoir rocks due to there relatively high porosity, and also act as source rocks due to the fair to good hydrocarbon generation capability.     

Temporal changes of fault seal and early charge of the Maui Gas-condensate field,Taranaki Basin,New Zealand

Fault seal due to juxtaposition or the generation of low-permeability fault rock has the potential to change through time with displacement accumulation. Temporal variations in cross-fault flow of hydrocarbons have been assessed for the Cape Egmont Fault (CEF), Taranaki Basin New Zealand, using displacement backstripping, juxtaposition and Shale Gouge Ratio (SGR) analysis. The timing of hydrocarbon migration and charge of the giant Maui Gas-condensate Field across the CEF have been assessed using seismic reflection lines (2D & 3D), coherency cubes, VShale curves from the Maui-2 well and PetroMod modelling. Displacement–backstripping analysis suggests that between the Late Miocene and early Pleistocene (5.5 and 2.1 Ma) sandstone reservoir units of the Maui Field (Mangahewa, Kaimiro and Farewell Formations) and underlying source rocks (Rakopi Formation) were partly juxtaposed across the CEF with low SGRs (< 0.2) present in the fault zone. Following 2.1 Ma SGRs increased to 0.2–0.55 adjacent to the Eocene–Palaeocene reservoir succession which was not in juxtaposed contact with source rocks. PetroMod modelling using these SGR values and juxtaposition relationships supports cross-fault flow prior to 2.1 Ma with later charge across the fault being less likely. Gas chimneys and the gas–water contact in the Eocene reservoir proximal to the fault suggest that despite limited cross-fault flow, upward leakage of hydrocarbons from the reservoir occurred after 2.1 Ma, possibly associated with active fault movement or fracturing related to faulting, and may account for the loss of an early oil phase.     

Constraining tectonic compression processes by reservoir pressure evolution: Overpressure generation and evolution in the Kelasu Thrust Belt of Kuqa Foreland Basin,NW China

The Kuqa Foreland Basin (KFB) immediately south of the South Tianshan Mountains is a major hydrocarbon producing basin in west China. The Kelasu Thrust Belt in the basin is the most favorable zone for hydrocarbon accumulations. Widespread overpressures are present in both the Cretaceous and Paleogene reservoirs with pressure coefficients up to 2.1. The tectonic compression process in KFB resulted from the South Tianshan Mountains uplift is examined from the viewpoint of the overpressure generation and evolution in the Kelasu Thrust Belt. The overpressure evolution in the reservoir sandstones were reconstructed through fluid inclusion analysis combined with PVT and basin modeling. Overpressures at present day in the mudstone units in the Kelasu Thrust Belt and reservoir sandstones of the Dabei Gas Field and the Keshen zone are believed to have been generated by horizontal tectonic compression. Both disequilibrium compaction and horizontal tectonic compression are thought to contribute to the overpressure development at present day in the reservoir of the Kela-2 Gas Field with the reservoir sandstones showing anomalously high primary porosities and low densities from wireline log and core data. The overpressure evolution for the Cretaceous reservoir sandstone in the Kelasu Thrust Belt evolved through four stages: a normal hydrostatic pressure (>12–5 Ma), a rapidly increasing overpressure (∼5–3 Ma), an overpressure release (∼3–1.64 Ma) and overpressure preservation (∼1.64–0 Ma). Overpressure developed in the second stage (∼5–3 Ma) was generated by disequilibrium compaction as tectonic compression due to the uplift of the Tianshan Mountains acted at the northern monocline of KFB from 5 Ma to 3 Ma, which provided abundant sediments for the KFB and caused the anomalously high sedimentation rate during the N₂k deposition. From 3 Ma to 1.64 Ma, the action of tectonic compression extended from the northern monocline to the Kelasu Thrust Belt and returned to the northern monocline of KFB from 1.64 Ma to present day. Therefore, the horizontal tectonic compression was the dominant overpressure mechanism for the overpressure generation in the third stage (∼3–1.64 Ma) and overpressure caused by disequilibrium compaction from 5 Ma to 3 Ma was only preserved in the Kela-2 Gas Field until present day.     

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).     

Kinetic simulation of hydrocarbon generation from lacustrine type I kerogen from the Songliao Basin: Model comparison and geological application

Eight lacustrine Type I kerogen samples from the Songliao Basin were pyrolyzed using the Rock-Eval equipment, and parallel first-order reaction models including the model with a single frequency factor and a discrete distribution of activation energies (SFF model) and the model with multiple frequency factors and a discrete distribution of activation energies (MFF model) were adopted to analyze kinetic characteristics of hydrocarbon generation of the Type I kerogen samples. The results show that the MFF and SFF models can satisfactory simulate hydrocarbon generation under laboratory conditions and the Type I kerogen shows relatively concentrated activation energy distributions (activation energies of MFF model range from 190 kJ/mol to 250 kJ/mol, activation energies of SFF model range from 220 kJ/mol to 240 kJ/mol), which indicates a homogeneous chemical bond structure of the Type I kerogen. The hydrocarbon generated curves from Type I kerogen were calculated by using the two models with a linear heating rate (3.3 K/Ma). It indicates that the hydrocarbon generation potentials (reaction fractions) are underestimated by using the SFF model during the kerogen thermal degradation for the components with chemical bond of lower and higher activation energies, while this problem can be avoided by using the MFF model. The calculated temperatures for 50% transformation ratio (TR) of all samples differ by as much as 20 °C. For the SFF model, the hydrocarbon generation curve obtained by using the weighted averaged kinetic parameters and the SFF model almost includes every curve calculated by using its own kinetic parameters. While the curve obtained by using the weighted averaged kinetic parameters and the MFF model cannot include every curve for all samples, it lies at the position of the averaged curve of all samples. The application of the MFF model in Songliao Basin shows that if TR 10% is taken as the onset of hydrocarbon generation, the threshold depth of hydrocarbon generation is about 1700 m, which is consistent with other geochemical parameters, such as S₁/TOC, S₁/(S₁ + S₂) and HC/TOC.     

Effect of sedimentary heterogeneities on hydrocarbon accumulations in the Permian Shanxi Formation,Ordos Basin,China: Insight from an integrated stratigraphic forward and petroleum system modelling

Sedimentary heterogeneities are ubiquitous in nature and occur over a range of scales from core, reservoir to basin scales. They may thus exert significant influences on hydrocarbon generation, migration and accumulation. The sedimentary heterogeneities of the Permian Shanxi Formation in the Ordos Basin, China were modelled using Sedsim, a stratigraphic forward modelling program. The simulation results were then used to construct a 3D petroleum system model using PetroMod. The effects of sedimentary heterogeneities on hydrocarbon accumulations were evaluated by comparing the integrated Sedsim-PetroMod model with the classic 3D basin model. The Sedsim simulation shows that considerable sedimentary heterogeneities are present within the Shanxi Formation, as a result of the interplay of the initial topography, tectonic subsidence, base level change and sediment inputs. A variety of lithologies were developed both laterally and vertically within the Shanxi Formation at kilometre and metre scales, respectively, with mudstones mainly developed in the depositional centre, while sandstones developed in the southern and northern margin areas. A typical source-ward retrogradation is well developed within the Lower Shanxi Formation.A base-case classic 3D basin model was constructed to quantify the Permian petroleum system in the Ordos Basin. The geological and thermal models were calibrated using Vr and borehole temperature data. The source rocks of the Upper Paleozoic became mature (R_o > 0.5%) and high mature (R_o > 1.2%) in the late Triassic and late Jurassic, respectively, in the central and southern areas. During the Early Cretaceous, a tectonically induced geothermal event occurred in the southern Ordos Basin. This caused the source rocks to reach over maturity (R_o > 2.0%) quite rapidly in the early Late Cretaceous in the central and southern areas. All the source rock transformation ratios (TR) at present are greater than 70% in the P₁ coal and P₁ mudstone layers with TR values approaching 100% in the central and southern areas. The transformation ratios of the P₁ limestone are close to 100% over the entire interval.In the base-case model, a large amount of hydrocarbons appear to have been expelled and migrated into the Shanxi Formation, but only a minor amount was accumulated to form reservoirs. In the model, the Shanxi Formation sandstone layer was set to be homogeneous vertically and there was no regional seal rocks present at the top of the Shanxi Formation. Therefore hydrocarbons could not be trapped effectively with only minor accumulations in some local structural highs where hydrocarbons are trapped both at the top and in the up-dip direction by the adjacent mudstone facies. In contrast, the integrated Sedsim-PetroMod model takes into account of the internal lithological and sedimentary facies heterogeneities within the Shanxi Formation, forming complex contiguous sandstone-mudstone stacking patterns. Hydrocarbons were found to have accumulated in multiple intervals of lithological traps within the Shanxi Formation. The results indicate that lithological distinctions, controlled by sedimentary heterogeneities in three dimensions can provide effective sealing in both the top and up-dip directions for hydrocarbon accumulations, with gas being mainly accumulated near the depocentre where lithological traps usually formed due to frequent oscillations of the lake level.     

A new possible giant hydrocarbon generated formation: The Upper Triassic source rock in Southwestern Junggar Basin,NW China

The Triassic formation is a possible new giant hydrocarbon generated formation in Northwest China and Mid-Asia. Taking the Upper Triassic formation in the Sikeshu Sag in Junggar Basin as an example, based on the comprehensive analysis on the geochemical characteristics of the cores and the dark mudstone of the outcrops and reservoir formation conditions, we have evaluated the Upper Triassic source rocks by comparing with those in the Ulungu Depression, and reached the following findings. Firstly, the Upper Triassic formation is mainly composed of dark mudstone and sandy mudstone deposits, and the hydrocarbon source rock is mainly distributed in the middle and upper parts with a thickness range of 100–150 m and area of 3500 km². Secondly, the source rock, moderate in organic matter abundance (with TOC range of 1%–3%), has the material basis for hydrocarbon generation. Thirdly, the organic matter has high percentage of sapropelinite, and is dominated by type II₂. Fourthly, the degree of the thermal evolution is moderate, and the source rock with R_o higher than 0.7% has a distribution area of about 1800 km², providing the conditions of massive hydrocarbon generation. Fifthly, the source rock has great burial depth and wide distribution; the source rock with a R_o of higher than 0.7% and thickness of more than 100 m has an area of around 1400 km², implying huge resource potential. Sixthly, the next step exploration should focus on highly mature hydrocarbon generation central area in the Upper Triassic - Lower Jurassic in the east of the sag to search for and confirm favorable traps. The research findings have important reference value for promoting the resource status of, deepening the understanding of reservoir formation, and clarifying the exploration direction in the Sikeshu Sag and other periphery Mid-Asia areas.     

A giant (5.3 × 10 m) middle Miocene (c. 15 Ma) sediment mound (M1) above the Siri Canyon, Norwegian–Danish Basin: Origin and significance

A large-scale enigmatic mound structure (M1) has been discovered in middle Miocene strata of the Norwegian–Danish Basin, c. 10 km east and updip of the Central Graben. It is located about 1 km beneath the seabed and clearly resolved by a 3D seismic data set focused on the deeper, remobilised, sand-filled Siri Canyon. M1 comprises two culminations, up to 80 m high and up to 1400 m long, constituting a sediment volume of some 5.3 × 10⁷ m³. It is characterized by a hard reflection at the top, a soft reflection at the base, differential compaction relative to the surrounding sediments, and 10 ms TWT velocity pull up of underlying reflections, indicating a relatively fast mound fill, attributed to the presence of sand within the mound. Internal seismic reflections are arranged in an asymmetric concentric pattern, suggesting a progressive aggradation to the NW, downstream to a mid-Miocene contour current system. Numerous elongated pockmarks occur in the upper Miocene succession close to the mound and indicate that the study area was influenced by gas expulsion in the mid- and late Miocene.The reflection configuration, velocity, dimensions, regional setting, and isolated location can best be explained by interpreting the mound as a giant sand volcano extruded >1 km upward from the Siri Canyon during the middle Miocene (c. 15 Ma). The likely causes of this remarkable structure include gas charge and lateral pressure transfer from the Central Graben along the Siri Canyon reservoir. While this is the first such structure described from this part of the North Sea, similar-aged sand extrudites have recently been inferred from seismic observations in the North Viking Graben, thus suggesting that the mid-Miocene was a time of widespread and intense sediment remobilization and fluid expulsion in the North Sea.     

Genesis and evolution of hydrocarbons entrapped in the fluorite deposit of Koh-i-Maran, (North Kirthar Range, Pakistan)

The exceptional development of coeval hydrocarbon and aqueous fluid inclusions (FI) in fluorite from the MVT-type ore deposit of Koh-i-Maran, Baluchistan (North Kirthar range, Pakistan), provides samples which are representative of the ore-forming fluid and which support the hypothesis of petroleum migration in the province. Primary brines at 125°C (10 wt% equ. NaCl) and secondary CH₄-rich brines at 135°C (7 wt% equ. NaCl), are recognised to be associated with oil migration in the fluid inclusions. They support the model of a per ascensum MVT (Mississippi Valley Type) stratabound hydrothermal deposit. A pressure–temperature path of 120–125°C to 165–200 bars is calculated from microthermometric data and PVT modelling of hydrocarbon FI using the modified Peng–Robinson Equation of State (IFP software) from primary cogenetic inclusions (oil and brines).The composition of gas and oil fractions is obtained by a combination of Synchrotron FTIR microanalysis and gas chromatography performed on individual fluid inclusions. The oil entrapped as a coeval primary fluid phase is a light aliphatic normal oil in the range C₈–C₃₅ with a high CO₂ content. The brown solid phase found systematically in the oil is probably asphaltene resulting from precipitation after trapping of the heavy fraction, which commonly occurs by decreasing pressure and temperature and\or by CO₂ injection. Later CH₄-rich brine influx probably modified part of the oil in the primary fluid inclusions because degraded oil is observed within such inclusions. Biomarkers obtained by GC-MS analysis indicate a terpane distribution quite similar to the nearest oil seepage in the Gokurt area. This result and the high CO₂ content of organic fluid inclusions indicate a restricted/confined sedimentary environment for the source rock, which could correspond to the Eocene Carbonate formation with type-II organic matter. A possible additional input of gas from the Sambar formation is suggested as feasible. The link between the fluid inclusion data and the geodynamic evolution lead us to propose a circulation of basinal fluids driven mainly by the fault system during dewatering in the foredeep. In Pakistan, they are coeval to major compressional NW–SE Oligocene episode in the thrust belt. The origin of the fluorine may be found in the basin sediments as well as near the basement. The brines originated in salt structures recognized in eocambrian at the decollement level, the source rock was already mature.     

Organic geochemical identification of reservoir oil–gas–water layers in the Junggar Basin,NW China

The identification of reservoir oil–gas–water layers is a fundamental task in petroleum exploration and exploitation, but is difficult, especially in cases of complex hydrocarbon migration and accumulation. In such cases, hydrocarbon remigration and dysmigration take place very commonly, leading to the presence of residual or paleo-oil accumulations and layers, which cannot be easily identified or misinterpreted as oil layers by conventional logging and geophysical data. In this paper, based on a case study in the Luxi area of the central Junggar Basin, NW China, we seek to characterize such layers in terms of organic geochemistry. We suggest specific indicator parameters of organic geochemistry such as the chloroform bitumen content of reservoir extracts, which is usually >1.0% in oil layers. We explore the application of grains containing oil inclusions (GOI) (the ratio of mineral grains containing oil inclusions to the total number of mineral grains) for the identification of oil–gas–water layers in the Junggar Basin for the first time; this method has been used elsewhere. The maximum GOI values for the oil layers, oil–water layers, water layers and dry layers are >11%, 7%–11%, 6%–7% and <6%, respectively. In addition, gas layers and heavy-oil layers that are difficult to identify by conventional organic geochemical parameters were identified using biomarkers. The typical characteristics of the soluble reservoir bitumen in the gas layers include a much greater abundance of tricyclic terpanes (two times in general) relative to pentacyclic terpanes and a tricyclic terpane distribution of C₂₀ > C₂₁ > C₂₃. In contrast, the typical characteristic of the heavy-oil layers is the presence of 25-norhopanes in reservoir bitumen extracts. These specific indicators can be applied in the Junggar Basin and in similar settings elsewhere.     

Structural regime and its impact on the mechanism and migration pathways of hydrocarbon seepage in the southern Gulf of Suez rift: An approach for finding new unexplored fault blocks

A Natural active oil seepage occurs at the intersection of the NW-oriented rift coastal fault and a NE-oriented cross fault which bound the southwest dipping Little Zeit tilted fault block at the southwestern side of the Gulf of Suez, Egypt. Detailed surface geological mapping followed by subsurface mapping using aeromagnetic, seismic and borehole data of Ras El Ush oilfield (the nearest oil field to the seepage) provide a reliable hydrocarbon migration pathway model of the area.The proposed model suggests that hydrocarbons migrated upward at the intersection of a NE-oriented and the NW-oriented rift coastal faults where they found their way to the surface. The Nubia Sandstone occurs south of Ras El Ush oilfield in a trap door structure and probably entrapped some of the migrating hydrocarbons while a probable oil-water-contact at −1000 m which resulted into the migration of hydrocarbon through the damage zone of the northeast fault.The original oil in place of the predicted reservoir is estimated to be more than 47.5 MMBO which encourages the design makers for more investigation of this reservoir to increase its certainty and putting it in the plan of the future investments.     

Hydrocarbon plumbing systems above the Snøhvit gas field: Structural control and implications for thermogenic methane leakage in the Hammerfest Basin,SW Barents Sea

Based on the analysis of the high-resolution 3D seismic data from the SW Barents Sea we study the hydrocarbon plumbing system above the Snøhvit and Albatross gas field to investigate the geo-morphological manifestation and the dynamics of leakage from the reservoir. Fluid and gas escape to the seafloor is manifested in this area as mega-pockmarks 1–2 km-wide, large pockmarks (<100 m wide) and giant pockmarks 100–300 m-wide. The size of the mega pockmarks to the south of the study area may indicate more vigorous venting, whilst the northern fluid flow regime is probably characterised by a widespread fluid and gas release. Buried mega depressions and large-to-giant pockmarks are also identified on the base Quaternary and linked to deep and shallow faults as well as to seismic pipes. A high density of buried and seafloor giant pockmarks occur above a network of faults overlying an interpreted Bottom Simulating Reflector (BSR), whose depth coincides with the estimated base of the hydrate stability zone for a thermogenically derived gas hydrate with around 90 mol% methane. Deep regional faults provide a direct route for the ascending thermogenic fluids from the reservoir, which then leaked through the shallow faults linked to seismic pipes. It is proposed that the last episodic hydrocarbon leakage from the reservoir was responsible for providing a methane source for the formation of gas hydrates. We inferred that at least two temporally and dynamically different fluid and gas venting events took place in the study area: (1) prior to late Weichselian and recorded on the Upper Regional Unconformity (URU) and (2) following the Last Glacial Maximum between ∼17 and 16 cal ka BP and recorded on the present-day seafloor.