Hydrocarbon Expulsion Research Articles

Geochemistry and origins of natural gases in the Yinggehai and Qiongdongnan basins, offshore South China Sea

Four gas fields and a number of gas-bearing structures have been discovered in the Yinggehai and Qiongdongnan basins offshore South China Sea. Chemical and isotopic data indicate the presence of at least three genetic groups of gases in these basins: biogenic gas, thermogenic gas, and gases with mixed origin. Thermogenic gases produced from the Yacheng field are characterized by relatively high contents of benzene and toluene, relatively low δ 13C values of toluene, and high abundance of bicadinanes and oleanane in the associated condensates, showing good correlation with the coal-bearing sequence of the Yacheng Formation in the Qiongdongnan Basin. In contrast, the gases from the DF1-1 and LD gas fields contain high amounts of N 2 and CO 2, low to moderate amounts of benzene and toluene, with relatively high δ 13C values of toluene. These characteristics correlate well with the Miocene neritic shales in the Yinggehai Basin. Analyses on potential source rock samples indicate excellent gas source potential for both the coal-bearing sequence in the Yacheng Formation and the Miocene neritic shales containing type III∼II2 kerogens. As the result of recent rapid subsidence and sedimentation, high temperature and overpressure systems are well developed in the Yinggehai and Qiongdongnan basins. The rapid heating resulted in advanced maturation of organic matter deposited in normally pressured and overpressured strata, whereas the strongly overpressured systems led to retarded organic matter maturation, postponing the time when the source rocks reached peak gas generation. Results of 1-D modeling indicate that the coal-bearing Yacheng Formation in the Yacheng Sag reached peak gas generation during mid Miocene-Pliocene time, after the deposition of upper Oligocene to lower Miocene reservoir rocks. The lower-mid Miocene marine shales reached their peak gas generation stage during the Pliocene-Quaternary in the central Yinggehai basin, supplying abundant gases to charge the Pliocene reservoirs. More importantly, focused-episodic gas migration significantly increased the hydrocarbon expulsion efficiencies of source rocks, and thus provided favorable conditions for the accumulation of large amounts of gases in the diapiric structures in a very short geological time. The gas–source relationship for the Yacheng field suggests dominantly short–distance gas migration and thus strong source facies controls on the geographic distribution of gas fields within the Qiongdongnan Basin.

Salt Diapirs, Salt Brine Seeps, Pockmarks and Surficial Sediment Creep and Slides in the Canary Channel off NW Africa

Circular to elliptical mounds in the Canary Channel with reliefs of 75 to 375 m and diameters of 4 to 8 km partially surrounded by moats with reliefs of 25 to 75 m, were formed by piercement of the seafloor by Mesozoic evaporites. Several long gullies, < 1km wide, with abrupt terminations and pockmarks associated with these mounds were probably eroded by dense brine and hydrocarbon seeps. The salt brines that eroded the gullies were formed where salt diapirs intersect the seafloor, or in the subsurface by circulating ground water heated by igneous activity along the Canary Ridge. If the brines originated in the subsurface they reached the seafloor along faults. Displacement of the surficial sediments by sliding and creep is probably the result of the expulsion of hydrocarbons and/or vertical motion of the Mesozoic evaporites. Microtopographic features along or near the east flank of the Canary Ridge are the creation of uplift of the ridge, hydrothermal activity, mass wasting processes and turbidity currents.

Dating diagenetic monazite in mudrocks: constraining the oil window?

Authigenic monazite nodules, increasingly recognized in Pre-Mesozoic mudrock successions, provide a means for dating diagenesis by exploiting trace uranium within the monazite structure. But, dating is difficult in practice because of zonation and abundant host rock inclusions. We report here a refined technique that has yielded a date of 419 ± 14 Ma 2 σ MSWD = 1.2 for a 17-point Pb–Pb regression age from a Telychian (Silurian: late Llandovery) mudrock from central Wales. SHRIMP analyses of monazite nodules from the same horizon are consistent with this, and additionally demonstrate concordance of the U–Pb and Th–Pb systems. These results open the door to providing robust dates for a phase of burial-related diagenesis which, in Wales, seems approximately coincident with, and perhaps was related to, hydrocarbon expulsion.

Évolution thermique des séries sédimentaires de la Marge ardéchoise : étude pétrographique de la matière organique et des argiles

Two wells, Balazuc (BA1) and Morte-Merie (MM1), located in a confined area (1200 m apart) and separated by the Uzer fault (a Liassic structure with a dip fault of 1300 m) were analysed using conventional methodologies and techniques (PRV, TAI, XRD, STEM) in order to compare the diagenetic evolution of clays and organic matter. The thermal convective process allows the circulation of hot fluids and the oxidation of organic matter. The conductive process allows the maturation of the organic matter, the expulsion of hydrocarbons and the deposit of pyrobitumes in the migration channels

Evaluating the timing of oil expulsion: about the inverse behaviour of light hydrocarbons and oil asphaltene kinetics

This paper deals with natural temperature records in the heavy (asphaltenes) and the light fractions (C7—light hydrocarbons) of petroleum. Two sets of marine oils formed from different source rocks and petroleum systems were studied using asphaltene kinetics and light hydrocarbon analysis. Both fractions have been reported to contain information about the temperature the respective oils have been exposed to in the subsurface. These indicated temperatures generally correspond to the conditions in the source rock when expulsion occurred. Bulk kinetic analysis of reservoir oil asphaltenes as well as light hydrocarbon (LH) analysis (of dimethylpentanes) were used here in order to evaluate the expulsion temperatures. Surprisingly, when considering information coming from both fractions, an inverse trend between LHs expulsion temperatures (Ctemp) and asphaltenes (Tasph.) can be observed—high Tasph (asphaltene temperatures) occur with low LH Ctemp (light hydrocarbon expulsion temperatures) and low Tasph can be observed when Ctemp is high. These differences are of fundamental importance for the use of such geochemical data in calibrating numerical basin models. The reason for this inverse behaviour is possibly due to the different expulsion behaviour of light hydrocarbons and the heavy fraction of oils, especially when the source rocks contain only moderate amounts of organic matter. In addition it has to be considered that the temperature predictions obtained using asphaltene kinetic analysis are related to the onset temperature of petroleum expulsion, while light hydrocarbons provide, at best, average expulsion temperatures.

HYDROCARBON GENERATION AND CHARGING IN THE OCTOBER FIELD, GULF OF SUEZ, EGYPT

Source rocks on‐structure in the October field are not sufficiently mature to have expelled hydrocarbons at the present day. l‐D modelling of a pseudo‐well in the deep October South Trough demonstrates that the Eocene Thebes and Senonian Sudr Formations are presently mature at depths greater than 3km. However, only the carbonate‐rich Sudr Formation has generated sufficient hydrocarbons for expulsion to take place at depths shallower than 3.5km, suggesting that reservoired oil in the October field originates predominantly from source rocks of this unit. Model results indicate that hydrocarbon expulsion from this source may have commenced as early as 20Ma in kitchen depocentres adjacent to the October field, and continued through the Pliocene.Migration routes predicted from 2‐D modelling are complex and require downward expulsion from the Sudr Formation east and west of the October field to charge the Palaeozoic Nubian Sandstone. Mature Sudr Formation in the October South Trough first charges the Nubian and then lower Senonian Matulla Formation reservoirs in the NW compartments of the October field via flow across the NW bounding fault. The mature Sudr Formation in the Baba Trough to the SE charged the Matulla Sandstones on the eastern flanks of the October field which then back‐filled to spill into the Nubian Sandstones. Hydrocarbons generated from the Thebes Formation contribute only minor volumes to the predicted accumulations.The presence of trap‐bounding faults and their sealing properties is shown to be a key sensitivity for charging the October field and related structures. Fault seal is required to charge known accumulations and match known hydrocarbon column heights, but extending shale smear into the Nubian Sandstone prevents the crestal October field structure from charging.The Matulla Formation sandstones are a regional migration fairway providing charge for the Ras Budran field and Nubian Sandstone prospects to the west of the October field. Younger Mesozoic sandstones are charged by vertical migration through seals and along faults. This regional migration sequence as described for the October field is likely to Maher Ayyad of BG Egypt very kindly gave access to the seismic cross section used in the study, as well as guiding our understanding of the regional geology of the Gulf of Suez, and also provided a constructive review of the manuscript. EGPC generously provided access to well data and support for Magdi El‐Ghamri. Colin Harwood (BG Group) and Dan Carruthers and John Bunney (Permedia Research Group Inc.) commented on early drafts of the manuscript. BG Group is thanked for permission to publish.

Coal as a source rock for oil: a review

The geological debate about whether, and to what extent, humic coals have sourced oil is likely to continue for some time, despite some important advances in our knowledge of the processes involved. It is clear that not only liptinites, but also perhydrous vitrinites have the potential to generate hydrocarbon liquids in the course of natural coalification. Some liptinites, especially alginite, cutinite, and suberinite, contain a higher proportion of aliphatic moieties in their structure than other liptinites such as sporinite and resinite and are, therefore, more oil-prone. It is of potential value to be able to predict the several environments of deposition in which coals with high liptinite contents or containing perhydrous vitrinites may have been formed. Review of the distribution of oil-prone coals in time and space reveals that most are Jurassic–Tertiary with key examples from Australia, New Zealand, and Indonesia. Methods based both on experimental simulations and the examination of naturally matured samples have been used to determine the order of generation of hydrocarbons from different macerals. Results are not entirely consistent among the different approaches, and there is much overlap in the ranges of degradation, but it seems probable that in the natural environment vitrinites begin to generate early, followed by labile liptinites such as suberinite, then cutinite, sporinite, and, finally, alginite. Petroleum potential may be determined by experimental simulation of natural coalification or inferred through various micro-techniques, especially fluorescence and infrared (IR) spectroscopy, or bulk techniques such as elemental analysis and 13C NMR spectroscopy. The latter three techniques enable a measure of the polymethylene component of the coal, which now appears to be one of the best available approaches for determining petroleum potential. No method of experimental simulation of petroleum generation from coals is without criticism, and comparative results are highly variable. However, hydrous pyrolysis, confined pyrolysis, and forms of open-system hydrous pyrolysis approach acceptable simulations. Whether, and to what degree generated liquid hydrocarbons are expelled, has long been the central problem in ‘oil from coal’ studies. The structure of vitrinite was believed until recently to contain an interconnected microporous network in which generated oil would be contained until an expulsion threshold was attained. Recent studies show the pores are not interconnected. Combined with a dynamic model of pore generation, it now seems that expulsion of hydrocarbons is best explained by activated diffusion of molecules to maceral boundaries and ultimately by cleats and fractures to coal seam boundaries. The main reason for poor expulsion is the adsorption of oil on the organic macromolecule, which may be overcome (1) if coals are thin and interbedded with clastic sediments, or (2) if the coals are very hydrogen-rich and generate large quantities of oil. The existence of oil in vitrinite is attested to by solvent extractions, fluorescence properties, and by microscopic observations of oil and bitumen. Experimental simulation of expulsion of oil from coals has only recently been attempted. The relative timing of release of generated CO 2 and CH 4 could have considerable importance in promoting the expulsion of liquid hydrocarbons but the mechanism is unclear. As it is universally agreed that dispersed organic matter (DOM) in some shales readily generates and expels petroleum, it is curious that few consistent geochemical differences have been found between coal macerals and DOM in interbedded shales. Unambiguous evidence of expulsion from coals is limited, and in particular only a few commercial oil discoveries can be confidently correlated to coals. These include Upper Cretaceous Fruitland Formation coals in the USA, from which oil is produced; New Zealand Tertiary coals; and Middle Jurassic coals from the Danish North Sea. It is likely that coals have at least contributed to significant oil discoveries in the Gippsland Basin, Australia; in the Turpan Basin, China; and in the Kutei and Ardjuna basins in Indonesia, but this remains unproven. Early reports that early Jurassic coals in mid-Norway were a major source of the reservoired oils have been shown to be inaccurate. None of the proposed ‘rules of thumb’ for generation or expulsion of petroleum from coals seem particularly robust. Decisions on whether a particular coal is likely to have been an active source for oil should consider all available geological and geochemical information. The assumptions made in computational models should be well understood as it is likely with new understandings of processes involved that some of these assumptions will be difficult to sustain.

Assessment of hydrocarbon source rock potential of Polish bituminous coals and carbonaceous shales

We analyzed 40 coal samples and 45 carbonaceous shale samples of varying thermal maturity (vitrinite reflectance 0.59% to 4.28%) from the Upper Carboniferous coal-bearing strata of the Upper Silesian, Lower Silesian, and Lublin basins, Poland, to evaluate their potential for generation and expulsion of gaseous and liquid hydrocarbons. We evaluated source rock potential based on Rock-Eval pyrolysis yield, elemental composition (atomic H/C and O/C), and solvent extraction yields of bitumen. An attempt was made to relate maceral composition to these source rock parameters and to composition of the organic matter and likely biological precursors. A few carbonaceous shale samples contain sufficient generation potential (pyrolysis assay and elemental composition) to be considered potential source rocks, although the extractable hydrocarbon and bitumen yields are lower than those reported in previous studies for effective Type III source rocks. Most samples analysed contain insufficient capacity for generation of hydrocarbons to reach thresholds required for expulsion (primary migration) to occur. In view of these findings, it is improbable that any of the coals or carbonaceous shales at the sites sampled in our study would be capable of expelling commercial amounts of oil. Inasmuch as a few samples contained sufficient generation capacity to be considered potential source rocks, it is possible that some locations or stratigraphic zones within the coals and shales could have favourable potential, but could not be clearly delimited with the number of samples analysed in our study. Because of their high heteroatomic content and high amount of asphaltenes, the bitumens contained in the coals are less capable of generating hydrocarbons even under optimal thermal conditions than their counterpart bitumens in the shales which have a lower heteroatomic content.

ABSTRACT: Hydrocarbon Charge Assessment, Gulf of Mexico: Rates of Oil/Gas Generation from Source Rocks and Oil Asphaltenes

Analysis of petroleum systems from oil geochemistry in the Gulf of Mexico has provided inferences regarding sources for hydrocarbons. Source rocks from the Tertiary and Cretaceous have been have been reported in Mississippi Canyon. Other Cretaceous source rocks have been described from cores at DSDP Site 535. While these data and inferences from inversion of oil geochemistry provide very solid evidence as to the formations that are sourcing oil and gas deposits, they do not provide the data necessary to predict accurately hydrocarbon charge. Hydrocarbon charge is dependent not only on identification of the effective source of oil and gas deposits, but also the timing of hydrocarbon generation, expulsion, and entrapment. The timing of hydrocarbon generation is a function of the rate of source rock decomposition (kinetic parameters) under a given burial and thermal history. Bulk and compositional kinetic parameters measured on Tertiary source rocks show very broad hydrocarbon generation rates and much higher yields of dry and wet gas. DSDP Site 535 Cretaceous source rocks show considerable variation in the rates of hydrocarbon generation. Jurassic source rocks also show variable hydrocarbon generation rates that appear to be a function of the sulfur content. These kinetic data provide the ability to accurately model hydrocarbon charge - oil and gas - using sophisticated models appropriate for the Gulf of Mexico.

NEW PETROLEUM MODELS IN THE PEDIRKA BASIN, NORTHERN TERRITORY, AUSTRALIA

The northern Pedirka Basin in the Northern Territory is sparsely explored compared with its southern counterpart in South Australia. Only seven wells and 2,500 km of seismic data occur over a prospective area of 73,000 km2 which comprises three stacked sedimentary basins of Palaeozoic to Mesozoic age. In this area three petroleum systems have potential related to important source intervals in the Early Jurassic Eromanga Basin (Poolowanna Formation), the Triassic Simpson Basin (Peera Peera Formation) and Early Permian Pedirka Basin (Purni Formation). They are variably developed in three prospective depocentres, the Eringa Trough, the Madigan Trough and the northern Poolowanna Trough. Basin modelling using modern techniques indicate oil and gas expulsion responded to increasing early Late Cretaceous temperatures in part due to sediment loading (Winton Formation). Using a composite kinetic model, oil and gas expulsion from coal rich source rocks were largely coincident at this time, when source rocks entered the wet gas maturation window.The Purni Formation coals provide the richest source rocks and equate to the lower Patchawarra Formation in the Cooper Basin. Widespread well intersections indicate that glacial outwash sandstones at the base of the Purni Formation, herein referred to as the Tirrawarra Sandstone equivalent, have regional extent and are an important exploration target as well as providing a direct correlation with the prolific Patchawarra/Tirrawarra petroleum system found in the Cooper Basin.An integrated investigation into the hydrocarbon charge and migration history of Colson–1 was carried out using CSIRO Petroleum’s OMI (Oil Migration Intervals), QGF (Quantitative Grain Fluorescence) and GOI (Grains with Oil Inclusions) technologies. In the Early Jurassic Poolowanna Formation between 1984 and 2054 mRT, elevated QGF intensities, evidence of oil inclusions and abundant fluorescing material trapped in quartz grains and low displacement pressure measurements collectively indicate the presence of palaeo-oil and gas accumulation over this 70 m interval. This is consistent with the current oil show indications such as staining, cut fluorescence, mud gas and surface solvent extraction within this reservoir interval. Multiple hydrocarbon migration pathways are also indicated in sandstones of the lower Algebuckina Sandstone, basal Poolowanna Formation and Tirrawarra Sandstone equivalent. This is a significant upgrade in hydrocarbon prospectivity, given previous perceptions of relatively poor quality and largely immature source rocks in the Basin.Conventional structural targets are numerous, but the timing of hydrocarbon expulsion dictates that those with an older drape and compaction component will be more prospective than those dominated by Tertiary reactivation which may have resulted in remigration or leakage. Preference should also apply to those structures adjacent to generative source kitchens on relatively short migration pathways. Early formed stratigraphic traps at the level of the Tirrawarra Sandstone equivalent and Poolowanna Formation are also attractive targets. Cyclic sedimentation in the Poolowanna Formation results in two upward fining cycles which compartmentalise the sequence into two reservoir–seal configurations. Basal fluvial sandstone reservoirs grade upwards into topset shale/coal lithologies which form effective semi-regional seals. Onlap of the basal cycle onto the Late Triassic unconformity offers opportunities for stratigraphic entrapment.

Petroleum generation and accumulation in the Golfo San Jorge Basin, Argentina: a basin modeling study

The Golfo San Jorge Basin, located in Patagonia, is very important for the oil and gas production of Argentina. In spite of the long history of exploration and production, few geochemical studies were performed until now. For this study, a set of possible source rocks was analyzed by organic geochemical and petrographical methods. The samples of the Pozo D-129 Fm. range from mature to overmature, and contain from less than 0.5 to 2.45% TOC. There is some evidence indicating an algal origin of the more hydrogen-rich kerogen present in part of the basin. Almost all the samples of Pozo Anticlinal Aguada Bandera and Pozo Cerro Guadal Fm. are overmature. TOC values range from less than 0.5 to 2.5%. The maturation of source rocks and generation, expulsion and migration of hydrocarbons was evaluated by means of 1D and 2D basin models. The 1D models constructed for the western part of the basin and 2D models applied for the eastern part both indicate maximum burial in Miocene times. The thickness of the Tertiary at times of maximum burial ranged from 1000 to 1500 m and the generally small Tertiary thickness now present in the fold belt region is assumed to be the result of erosion. The main tectonic inversion took place in the Late Neogene. The models strongly suggest that a magmatic event between 20 and 30 Ma, combined with the maximum burial at Miocene times produced a very important pulse in hydrocarbon generation within the major part of the basin. Dated intrusive and extrusive magmatic rocks extended all over the basin account for this period of elevated heat flow. Migration pathways are extensively discussed for the 2D model. Probably, major faults acted as important conduits for petroleum.

Arc magmatism and hydrocarbon generation in the northern Taranaki Basin, New Zealand

A Middle–Late Miocene andesitic arc named the Mohakatino Volcanic Centre is buried beneath younger sediments in the northern part of the Taranaki Basin, New Zealand’s primary oil production province. Volcanoes of the centre cover an area of about 3200 km 2 . An estimated 7000±3000 km 3 of andesite were erupted from the centre and between 1000 to 2500 km 3 of magma were intruded into the basement beneath the volcanic cones. The key element of the petroleum system altered by magmatism is the maturity of source rocks and the timing of expulsion, although volcanism also contributes to the formation of potential reservoirs and traps. In the northern Taranaki Basin, two periods of hydrocarbon expulsion occurred: following magmatism (14 Ma to about 8 Ma), and following renewed burial (since about 4 Ma). Thermal models indicate that Late Cretaceous terrestrial source rocks close to large magmatic intrusions became fully mature during magmatism. Overlying marine source rocks are modelled to still be generating and expelling hydrocarbons to the present day. Hence hydrocarbon expulsion and the charge history of this basin is partly governed by Miocene magmatism. Results are also relevant to many petroleum basins that contain similar andesitic arc volcanic rocks.

Paleozoic Stratigraphy and Hydrocarbon Habitat of the Arabian Plate

ABSTRACTThe Paleozoic section became prospective during the early 1970s when the enormous gas reserves in the Permian Khuff reservoirs were delineated in the Gulf and Zagros regions, and oil was discovered in Oman. Since then, frontier exploration has targeted the Paleozoic System throughout the Middle East, driven by various economic considerations. The Paleozoic sequences were essentially deposited in continental to deep marine clastic environments at the Gondwana continental margin. Carbonates only became dominant in the Late Permian. The sediments were deposited in arid to glacial settings, reflecting the drift of the region from equatorial to high southern latitudes and back. Following late Precambrian rifting that formed salt basins in Oman and the Arabian Gulf region, the Cambrian-Devonian sequences were deposited on a peneplained continental platform. The entire region was affected by the Hercynian Orogeny, which climaxed during the Carboniferous. The orogeny manifested itself in a change in basin geometry, inversion tectonics, regional uplift and tectonism along the Zagros fault zone. This deformation caused widespread erosion of the Devonian-Carboniferous and older sections, and was probably caused by collision along the northern margin of Gondwana. The Paleozoic tectonic super cycle ended with the onset of break-up tectonics in the Permian, and the deposition of Khuff carbonates over the newly formed eastern passive margin. A major Paleozoic petroleum system embraces reservoir seal pairs spanning the Silurian to Permian sequences. Hydrocarbons occur in a variety of traps, and are sourced by the Silurian ‘hot shale’. A second petroleum system occurs in areas charged from upper Precambrian source rocks in the salt basins. Hydrocarbon expulsion estimates, taking into account secondary migration losses, suggest that some one trillion barrels of oil equivalent (BOE) may have been trapped from the Silurian ‘hot shale’ alone. However, the long and complex hydrocarbon geological evolution of the basin, combined with low acoustic contrasts between target rock units, difficult surface conditions, tight reservoirs, and deep subsurface environments, posed significant challenges to exploration and development. The critical success factor is the continuous innovative effort of earth scientists and subsurface engineers to find integrated technology solutions, that will render the Paleozoic plays economically viable.

HYDROCARBON PROSPECTIVITY OF THE DEEPWATER GIPPSLAND BASIN, VICTORIA, AUSTRALIA

After 35 years of successful exploration and development, the Gippsland Basin is perceived as a mature basin. Several world class fields have produced 3.6 billion (109) BBL (569 GL) oil and 5.2 TCF (148 Gm3) gas. Without additional discoveries, it is predicted that further significant decline in production will occur in the next decade.However, the Gippsland Basin is still relatively underexplored when compared to other prolific hydrocarbon provinces. Large areas are undrilled, particularly in the eastern deepwater part of the basin. Here, an interpretation of new regional aeromagnetic and deep-water seismic data sets, acquired through State and Federal government initiatives, together with stratigraphic, sedimentological and source rock maturation modelling studies have been used to delineate potential petroleum systems.In the currently gazetted deepwater blocks, eight structural trapping trends are present, each with a range of play types and considerable potential for both oil and gas. These include major channel incision plays, uplifted anticlinal and collapsed structures that contain sequences of marine sandstones and shales (deepwater analogues of the Marlin and Turrum fields), as well as large marine shale-draped basement horsts.The study has delineated an extensive near-shore marine, lower coastal plain and deltaic facies association in the Golden Beach Subgroup. These Late Cretaceous strata are comparable to similar facies of the Tertiary Latrobe Siliciclastics and extend potential source rock distribution beyond that of previous assessments. In the western portion of the blocks, overburden is thick enough to drive hydrocarbon generation and expulsion. The strata above large areas of the source kitchen generally dip to the north and west, promoting migration further into the gazetted areas.Much of the basin’s deepwater area, thus, shares the deeper stratigraphy and favourable subsidence history of the shallow water producing areas. Future exploration and production efforts will, however, be challenged by the 200–2500 m water-depths and local steep bathymetric gradients, which affect prospect depth conversion and the feasibility of development projects in the case of successful exploration.

Petroleum geological dynamics of Lower Paleozoic in the Ordos Basin, northwest China

Taking the hydrocarbon source rocks of Ordovician, Lower Paleozoic in the Ordos Basin as the main research object, the characteristics of petroleum geological dynamics about geohistory, geothermal history, hydrocarbon generation history and hydrocarbon expulsion history were studied by using the methods of basin numerical modeling dynamically and pool-forming dynamics. It is shown that the Ordovician strata had entirely undergone five stages of initial deposition, uplift and erosion, rapid subsidence, alternating uplift and subsidence, and differential uplift and erosion; that under the background of lower heat flow on the whole, the paleoheat flow of Ordovician strata in the basin could be divided into two large stages of relatively high heat flow values period before Cretaceous deposition and relatively low ones after it; that the thermal evolution of organic matters in the hydrocarbon source rocks of Ordovician had entered into high mature-postmature stage on the whole and the intensity of gas generated was greater than that of oil generated, the hydrocarbon being mainly natural gas; and that the curves of the intensity of oil and gas expulsion at each time unit showed the feature of multi-peak-type, the accumulative intensity of gas expulsion was greater than that of oil expulsion. Thus natural gas exploration potential is good.

Observation of hydrocarbon generation and migration of highly-matured carbonates by means of laser-induced fluorescence microscopy

Some important information on hydrocarbon generation, inclusion and migration in highly-matured carbonates of lower Palaeozoic age from the Ordos Basin and Tarim Basin has been analyzed by a newly-combined laser-induced fluorescence microscope (LFM) designed by our laboratory. The following information has been obtained from the lower Ordovician lamellar carbonates with equivalent vitrinite reflectance (R o) as high as 1.6%–1.7% and residual TOC of 0.14%–0.35% from the Ordos Basin: wide occurrences of oil and source macerais with strong fluorescence, includingG.Prisca alginite, lamalginite, telalginite and algae-detrinite; fluorescing asphalt among mineral crystals; some groundmass and spheroid-like reservoir bitumen with high maturation levels in the pores of dolomites. Various kinds of fluorescing organic inclusions and asphalt have been found in the carbonates, calcareous shales and silt-shales with high maturation levels from the Cambrian-Ordovician strata in the Tarim Basin. All this helps us find and evaluate significant and excellent source rocks for large- and middle-scale gas fields. The net and micro-net systems for hydrocarbon generation, expulsion and migration in carbonates have been revealed by the highly-powered laser-induced fluorescence microscopy.

Abstract: Modeling of thermal maturation and hydrocarbon generation and expulsion in Northern Tunisia thrust belt

Abstract: Modeling of thermal maturation and hydrocarbon generation and expulsion in Northern Tunisia thrust belt

Petrographic features of oil-prone coals from the Brunei-Muara District, Negara Brunei Darussalam

Petrological investigation of a number of coal samples from the Brunei-Muara District reveals the presence of oil-generative features commonly observed in oil-prone coals. These features include the occurrence of exsudatinite, oil globules, oil haze and changes in fluorescence intensity; all of which were observed to be associated with the maceral suberinite and bitumens in the samples studied. These liptinitic constituents, which are commonly associated with liptodetrinite, are regarded as the most oil­ prone components in the coals of the Brunei-Muara District. Exsudatinite is developed by fracturing of the vitrinite following generation of fluid hydrocarbons. This leads to expulsion of hydrocarbons under sufficient pressure to cause the fractures to develop and form exsudatinite crack network. This occurs at a relatively low thermal maturity level of 0.42 to 0.49%R o ' These coals are characterised by a high abundance of liptodetrinite, inertodetrinite and vitrodetrinite occurring within a desmocollinite (or collodetrinite) matrix, and occasional mineral matter. The presence of a high abundance of hydrogen­ rich liptodetrinite and its association with collodetrinite further enhances the oil-generative and expulsive features possessed by these coals . In these coals, liptodetrinite seems to be mostly derived from the breakdown of the suberinite-phlobaphinite framework, primarily by fragmentation of suberinite. This breakdown is associated with liquid hydrocarbon generation. The generation of liquid hydrocarbons by the liptodetrinite maceral, however, was not observed at this low thermal maturity and is likely to occur later at a relatively higher maturation level.

Paleozoic Petroleum System of Central Saudi Arabia

ABSTRACT An integrated geochemical model was developed to reconstruct the history of expulsion, migration and entrapment of Paleozoic oil and gas in the main regional Permian Unayzah Sandstone Reservoir in Central Saudi Arabia. The model indicates that by the Late Jurassic, approximately 140 million years ago (Ma), the principal Paleozoic source rock, the Lower Silurian Qusaiba “hot” shale, was mature in the deepest hydrocarbon “kitchens”. Hydrocarbon expulsion started during the Aptian and Albian (late Early to early Middle Cretaceous, 100 to 120 Ma). Expulsion of oil and gas is linked to three geochemical events. Primary kerogen cracking led to a first episode of expulsion about 120 Ma. Secondary heavy component and oil cracking resulted in a second episode of expulsion at approximately 100 Ma. Between 20 to 10 Ma, later uplift, and the resulting pressure drop in the source rock, led to a third expulsion phase. The first two expulsion episodes were gradual, whereas the third was more rapid and related to uplift of the Arabian Arch, opening of the Red Sea and the Zagros Orogeny during the Miocene. Expulsion of oil nearly terminated after the Late Cretaceous, while gas continued to be expelled, though at a lower rate, in the Tertiary. Peak gas expulsion occurred post Early Eocene with significant gas generation from secondary cracking of oil retained in the source rock. Gas was sourced either directly from kerogen, or from secondary cracking of heavy absorbed components or non-migrated oils. The expulsion of gas coincides with oil expulsion for the first two episodes because the gas and oil formed as a single phase. As a result of Tertiary Uplift, gas separated from the oil and re-migrated in the final episode (20 to 10 Ma).

Characteristics of hydrocarbon generation and expulsion in matrix and stylolite of carbonate rocks

Characteristics of organic matter content, hydrocarbon generation and expulsion of carbonate rocks are discussed by analysis of organic carbon and pyrolysis. There is a strong inhomogeneity in distribution of organic matter in carbonate rocks. The organic matter abundance is higher in stylolites, carbonate varves or marls, while it is the lowest in matrixes (purer carbonate rocks around stylolites). Because of stable thickness and broad area, marls and carbonate varves may become good source rocks. At the same depth, stylolites, carbonate varves and matrixes generate and expel hydrocarbons almost at the same time. Expulsion efficiency of carbonate varve is the highest; that of rnatrixes is the lowest and that of stylolites is between marl’s or carbonate varve’s and matrix’s.