Active Source Rocks Research Articles

Geochemical overview and undiscovered gas resources generated from Hamitabat petroleum system in the Thrace Basin, Turkey

Since the first drill in 1957, three oil, 19 gas and condensate fields have been discovered in the Thrace Basin. However, any petroleum system with its essential elements and processes has not been assigned yet. This study consists of two parts, (1) geochemical overview of the previous work in order to get a necessary help to construct a petroleum system and (2) calculation of quantitative undiscovered hydrocarbon resources generated from this system. An extensive overview study showed that the primary reservoir and source rocks in the Thrace Basin are the Middle Eocene Hamitabat sandstones and shales, respectively, hence it appears that the most effective petroleum system of the Thrace Basin becomes the Hamitabat (!) petroleum system. Currently, 18.5 billion m 3 of in-place gas, 2.0 million m 3 (12.7 million bbl) in-place waxy oil as well as minor amount of associated condensate were discovered from this system. This study showed that the regional distribution of the oil and gas fields almost overlapped with the previously constructed pod of active Hamitabat shales implying that short and up-dip vertical migration pathway of hydrocarbons from the source to trapping side was available. Thermal model demonstrated that hydrocarbon generation from the Hamitabat shales commenced in the Early Miocene. The amount of quantitative gas generation based on the mean-original TOC = 0.94 wt%, mean-original HI = 217 HC/g TOC and the volume of the pod of active source rock = 49 km 3 is approximately 110 billion m 3 of gaseous hydrocarbons that results in a high generation–accumulation efficiency of 17% when 18.5 billion m 3 of already discovered hydrocarbons are considered.

Geochemical analysis techniques and geological applications of oil-bearing fluid inclusions, with some Australian case studies

Reliable geochemical information of similar quality to conventional analyses of crude oils and source rocks can be obtained from oil-bearing fluid inclusions (FI). Carefully controlled analytical procedures including sample clean-up, procedural blanks and attention to detail are essential for the successful analysis of inclusion oils. The procedures are technically challenging, but if they are carefully followed, successfully analysed samples can include not only those with high abundances of oil inclusions, such as in current or palaeo-oil reservoirs, but also samples with low amounts of oil inclusions, such as those from oil migration pathways or from Proterozoic or even older rocks. A full range of hydrocarbons can be measured from inclusions, including low molecular weight hydrocarbons, n-alkanes, aliphatic biomarkers such as isoprenoids, hopanes and steranes, and aromatic hydrocarbons. There are many geological applications of the analysis of FI oils, which contribute to reducing regional exploration risk. This paper uses Australian case histories to illustrate the main applications of FI oil analysis. These include better constraining oil charge histories of reservoirs and identifying active source rocks previously unknown in a particular basin. The effects of oil-alteration by biodegradation and/or water-washing in the reservoir can be removed, mixing episodes in reservoirs can be deconvoluted, and the effects of drilling mud additives or other contaminants can be eliminated. Furthermore, the hydrocarbon composition and diversity of Earth's early biosphere can be constrained, and secondary migration pathways can be mapped across prospects or basins.

DEPOSITIONAL ENVIRONMENTS, ORGANIC MATURITY AND PETROLEUM POTENTIAL OF THE CRETACEOUS COAL-BEARING ATANE FORMATION AT QULLISSAT, NUUSSUAQ BASIN, WEST GREENLAND

Coals and coaly mudstones of the Cretaceous Atane Formation are exposed along the north coast of the island of Disko and the south coast of Nuussuaq peninsula, West Greenland. Numerous oil seepages have been found in the region, but the so-called Kuugannguaq oil type only occurs at the north coast of Disko. The oil is presumed to have been generated from coaly (Type III) source rocks in the Vaigat strait where the Atane Formation is thermally mature due to deep burial. The exposed coals and coaly mudstones may thus be thermally immature equivalents of the active source rocks. The exposed section at Qullissat on the island of Disko is composed of four sedimentary facies associations: delta plain, distributary channel, delta front, and transgressive sand sheet. Samples of coals and coaly mudstones from the delta plain association were analysed for their total organic carbon (wt % TOC) and total sulphur (wt % TS) contents, and their source rock potential was determined by Rock-Eval pyrolysis. The organic matter composition was analysed by reflected light microscopy and the thermal maturity was established by vitrinite reflectance measurements. The Qullissat samples were supplemented with source rock screening data from coals and coaly mudstones from the Atane Formation at Paatuut on the south coast of Nuussuaq. The coals and coaly mudstones from Qullissat are dominated by huminite, but several samples have a considerable content of inertinite. The mineral content is high in some samples. Inundations of the peat-mires may have been quite frequent resulting in the formation of the coaly mudstones. TS contents (0.13–8.97 wt %) and the presence of framboidal pyrite suggest that the precursor peats were influenced by seawater, and that peat formation probably occurred during rises in relative sea-level. The organic matter is thermally immature, and a constructed vitrinite reflectance gradient for the region suggests that the Qullissat section prior to exhumation was buried to 1,500–1,600 m depth. Hydrogen Index (HI) values from both Qullissat and Paatuut are generally low; estimated maximum HI values for three Qullissat coals yield values of 140–190 mg HC/g TOC. The coals are gas-prone and only marginally oil-prone, and may in addition possess a limited oil expulsion efficiency. The effective oil window extends from approximately 1.0–1.6%Ro and the start of the effective oil window is located at about 3,000 m depth. Very thick sedimentary successions in the Vaigat strait indicate that such burial depths have been reached for the Atane Formation offshore, and up-dip migration of hydrocarbons from these source rocks may have generated the Kuugannguaq oil seepage.

石油システム

“Petroleum system” concept had been rapidly developed during 90's in oil industry. Magoon and Dow (1994a, b) defined “a petroleum system” as “a natural system that encompasses a pod of active source rock and all related oil and gas and which includes all the geologic elements and processes that are essential if a hydrocarbon accumulation is to exist”. Basic idea of “petroleum system” concept is to focus on fluids (oil and gas) rather than rocks. The existence of fluids (oil and gas) is essential element to have oil and gas fields in sedimentary basins, and hence accurate analysis of them is essential investigation for the increase of discovery rate in oil and gas explorations.Development of new technologies such as biomarker and basin modeling boosted the introduction of “petroleum system” concept into oil industry. Biomarker technology enables to identify effective source rocks, which supply oil and gas to tarps. Basin modeling technology reveals dynamic process of oil and gas generation, migration and accumulation, which occurred in the past.

Near‐surface hydrocarbon anomalies in shelf sediments off Spitsbergen: Evidences for past seepages

As global warming occurs, the dissociation of bound methane on Arctic shelves due to ocean current temperature changes may become a major contributor to the global methane budget, and thus contribute to strong positive climate feedback mechanisms. However, little is known about the magnitude and fate of methane emissions from shallow submarine sediments to the atmosphere in the peculiar area. In this paper, we present one of the first direct evidences for seepage on the northwestern Barents Sea shelf. By studying the molecular and isotopic signatures of low‐molecular‐weight hydrocarbons in seawater, near‐surface sediment pore space and the sediment matrix at 26 locations, we provide a detailed view on the partitioning of gaseous hydrocarbons in the sediment‐water interface off Spitsbergen. In the free gas phase, low concentration of methane (∼28 ng/g wet Sediment) paired with constantly high isotopic values (∼−65‰) is consistent with high impact of methane oxidation on the isotopic composition. In contrast, high concentrations of adsorbed CH4 (up to 5292 ng/g wet <63 μm) and C2+ (ethane through pentane) (up to 1724 ng/g wet <63 μm) in the sediment matrix suggest that the adsorbed gas is reasonably well protected against microbial degradation. Moreover, the isotopic and molecular signatures of adsorbed CH4 (−38–−60‰; ∼100–∼5300 ng/g wet <63 μm) and C2H6 (−20–−36‰; ∼30–∼1700 ng/g wet <63 μm) indicate an integrated, but strongly varying signal of historic thermally derived hydrocarbon plumes plus in situ adsorbed gas of biological origin. This suggests a minimal exchange and unlike histories of free and adsorbed gas. The majority of gaseous hydrocarbons in the adsorbed pool may be the result of past seepages. Past upward flow of thermogenic gas and impregnation with mature hydrocarbons was particularly strong along tectonic lineaments. Active petroleum source rocks along the continental margin and migration of gaseous hydrocarbons at re‐activated fault systems might explain the anomalies along these conduits.

Material-balance assessment of the New Albany-Chesterian petroleum system of the Illinois basin

The New Albany-Chesterian petroleum system of the Illinois basin is a well-constrained system from which petroleum charges and losses were quantified through a material-balance assessment. This petroleum system has nearly 90,000 wells penetrating the Chesterian section, a single New Albany Shale source rock accounting for more than 99% of the produced oil, well-established stratigraphic and structural frameworks, and accessible source rock samples at various maturity levels. A hydrogen index (HI) map based on Rock-Eval analyses of source rock samples of New Albany Shale defines the pod of active source rock and extent of oil generation. Based on a buoyancy-drive model, the system was divided into seven secondary-migration catchments. Each catchment contains a part of the active pod of source rock from which it derives a petroleum charge, and this charge is confined to carrier beds and reservoirs within these catchments as accountable petroleum, petroleum losses, or undiscovered petroleum. A well-constrained catchment with no apparent erosional or leakage losses is used to determine an actual petroleum charge from accountable petroleum and residual migration losses. This actual petroleum charge is used to calibrate the other catchments in which erosional petroleum losses have occurred. Petroleum charges determined by laboratory pyrolysis are exaggerated relative to the actual petroleum charge. Rock-Eval charges are exaggerated by a factor of 4-14, and hydrous-pyrolysis charges are exaggerated by a factor of 1.7. The actual petroleum charge provides a more meaningful material balance and more realistic estimates of petroleum losses and remaining undiscovered petroleum. The total petroleum charge determined for the New Albany-Chesterian system is 78 billion bbl, of which 11.4 billion bbl occur as accountable in place petroleum, 9 billion bbl occur as residual migration losses, and 57.6 billion bbl occur as erosional losses. Of the erosional losses, 40 billion bbl were lost from two catchments that have highly faulted and extensively eroded sections. Anomalies in the relationship between erosional losses and degree of erosion suggest there is potential for undiscovered petroleum in one of the catchments. These results demonstrate that a material-balance assessment of migration catchments provides a useful means to evaluate and rank areas within a petroleum system. The article provides methodologies for obtaining more realistic petroleum charges and losses that can be applied to less data-rich petroleum systems.

Geochemistry and Origin of Some Natural Gases in the Plateau Province, Central Appalachian Basin, Pennsylvania and Ohio

The Appalachian Plateau is a large, elongate structural basin in the western part of the central Appalachians. In western Pennsylvania and eastern Ohio, the Plateau is a mostly wet gas (mean C{sub 2}-C{sub 5}/C{sub 1}-C{sub 5}=6.08%) district which has produced approximately one-third of all the natural gas produced in the entire Appalachian basin. We sampled gases from 22 wells and 5 cores to determine the possible utility of stable isotope geochemistry for interpreting the origin of the gases and correlating them with their probable sources. Methane {delta}{sup 13} C and {delta}C and {delta}D values range from -55.1 to -27.24% and -303 to -150% respectively. Corresponding ethane and propane values of selected samples range from -41.79 to -29.61% and -38.21 to -26.71%. Several gas samples exhibit isotopic reversals amoung the C{sub 1} to C{sub 3} hydrocarbons. The isotope data provide some potential insight into the origin of these gases and the timing and direction of their migration into different reservoirs. With few exceptions, the gases we analyzed are secondary, i.e. mixtures of gases varying origins or primary gases (original gas from a single, active source rock) which were altered by geological processes. Most samples originated as associated thermogenic gases generated frommore » Types I/II kerogens at source rock maturities ranging from early mature to overmature. Coalbed gases and some Upper Devonian gases appear to be mixtures of thermogenic and microbial hydrocarbons. We interpret several other gases from various Cambrian through Devonian reservoirs as mixtures of thermogenic gases.« less

Visualizing Petroleum Systems with a Combination of GIS and Multimedia Technologies: An Example from the West Siberia Basin: ABSTRACT

Petroleum system studies provide an ideal application for the combination of Geographic Information System (GIS) and multimedia technologies. GIS technology is used to build and maintain the spatial and tabular data within the study region. Spatial data may comprise the zones of active source rocks and potential reservoir facies. Similarly, tabular data include the attendant source rock parameters (e.g. pyroloysis results, organic carbon content) and field-level exploration and production histories for the basin. Once the spatial and tabular data base has been constructed, GIS technology is useful in finding favorable exploration trends, such as zones of high organic content, mature source rocks in positions adjacent to sealed, high porosity reservoir facies. Multimedia technology provides powerful visualization tools for petroleum system studies. The components of petroleum system development, most importantly generation, migration and trap development typically span periods of tens to hundreds of millions of years. The ability to animate spatial data over time provides an insightful alternative for studying the development of processes which are only captured in [open quotes]snapshots[close quotes] by static maps. New multimedia-authoring software provides this temporal dimension. The ability to record this data on CD-ROMs and allow user- interactivity further leverages the combination of spatial datamore » bases, tabular data bases and time-based animations. The example used for this study was the Bazhenov-Neocomian petroleum system of West Siberia.« less

A Successful Application of the Petroleum System Concept in the Camamu Basin, Offshore Brazil: ABSTRACT

The characterization of a major petroleum system in the Camamu basin, NE Brazil, was undertaken using a multidisciplinary approach involving geochemical, geological, geophysical and microbiostratigraphic research. This approach has greatly enhanced the level of understanding of the petroleum system concept in the area, allowing the identification of a new exploration target. The hydrocarbons sourced by the lowermost Cretaceous lacustrine fresh to brackish water black shales, started migration during the Early Cretaceous times, continuing up to now in some parts of the basin. The hydrocarbons were accumulated in Lower Cretaceous, Rio de Contas Formation lacustrine sandstone reservoirs, structured during the rifting process, and sealed by deep water lacustrine shales, or trapped in the Dom Joao Stage (Jurassic), Sergi Formation, against the footwall of major regional faults. The geochemical parameters indicate that the Camamu basin is basically oil prone. Mapping the geographic extent of the petroleum system emphasizes the association of the oil fields with the proposed pod of active source rocks. The integration of these data with a 2D-geochemical modelling allowed the prediction and characterization, in time and space, of the petroleum pathways from source to trap in the area. Two major petroleum systems were selected, as the most attractive, inmore » the Camamu Basin: the pre-rift Morro do Barro-Sergi (!) and synrift Morro do Barro-Rio de Contas (!). This approach allowed the identification of a new exploration target, in the latter one, which, after drilling, resulted in a 157 M bbl discovery, and brought a new insight for the hydrocarbon exploration in the basin.« less

Controls on the Distribution of Cretaceous Source Rocks in South America

More than thirty South American basins, exhibiting a variety of structural styles, contain petroleum source rocks of Cretaceous age. However, the presence of truly [open quote]world-class[close quote] source rocks, capable of supplying multi-billion barrel oil provinces, is restricted to relatively few basins and appears to be primarily a function of large scale Cretaceous tectonic setting. In Early Cretaceous times the best source rocks were preserved in both a southern ocean and in the rift between South America and Africa. By the Late Cretaceous, these southern and eastern continental limits had become narrow passive margins. In contrast, on the northern continental margin a wide shelf to a restricted tropical sea was developing at this time. Periodic upwelling enhanced surface productivity on this shelf, which led to development of some of the world's richest source rocks. On the tectonically active western margin moderate quality source rocks were forming in a series of back-arc basins, whilst further west, in the Pacific fore-arc, organic-rich intervals were rarely deposited. This article documents what is known about each of the explored basins (including the volume and character of discovered petroleums), it investigates the geologic factors which governed the richness and quality of petroleum source rocks andmore » it assesses how continued tectonic activity has modified or even destroyed primary source quality. Finally it predicts which of the as yet underexplored basins should contain good quality source rocks and could become prolific petroleum provinces of the future.« less

CONTINENTAL SHELF BASINS ON THE WEST TASMANIA MARGIN

The continental margin of western Tasmania is underlain by the southern Otway Basin and the Sorell Basin. The latter lies mainly under the continental slope, but it includes four sub-basins (the King Island, Sandy Cape, Strahan and Port Davey sub-basins) underlying the continental shelf. In general, these depocentres are interpreted to have formed at the 'relieving bends' of a major left-lateral strike-slip fault system, associated with 'southern margin' extension and breakup (seafloor spreading). The sedimentary fill could have commenced in the Jurassic; however, the southernmost sub-basins (Strahan and Port Davey) may be Late Cretaceous and Paleocene, respectively.Maximum sediment thickness is about 4300 m in the southern Otway Basin, 3600 m in the King Island Sub-basin, 5100 m in the Sandy Cape Basin, 6500 m in the Strahan Sub-basin, and 3000 m in the Port Davey Sub-basin. Megasequences in the shelf basins are similar to those in the Otway Basin, and are generally separated by unconformities. There are Lower Cretaceous non-marine conglomerates, sandstones and mudstones, which probably include the undated red beds recovered in two wells, and Upper Cretaceous shallow marine to non-marine conglomerates, sandstones and mudstones. The Cainozoic sequence often commences with a basal conglomerate, and includes Paleocene to Lower Eocene shallow marine sandstones, mudstones and marl, Eocene shallow marine limestones, marls and sandstones, and Oligocene and younger shallow marine marls and limestones.The presence of active source rocks has been demonstrated by the occurrence of free oil near TD in the Cape Sorell-1 well (Strahan Sub-basin), and thermogenic gas from surficial sediments recovered from the upper continental slope and the Sandy Cape Sub-basin. Geohistory maturation modelling of wells and source rock 'kitchens' has shown that the best locations for liquid hydrocarbon entrapment in the southern Otway Basin are in structural positions marginward of the Prawn-1 well location. In such positions, basal Lower Cretaceous source rocks could charge overlying Pretty Hill Sandstone reservoirs. In the King Island Sub-Basin, the sediments encountered by the Clam-1 well are thermally immature, though hydrocarbons generated from within mature Lower Cretaceous rocks in adjacent depocentres could charge traps, providing that suitable migration pathways are present. Whilst no wells have been drilled in the Sandy Cape Sub-basin, basal Cretaceous potential source rocks are considered to have entered the oil window in the early Late Cretaceous, and are now capable of generating gas/condensate. Upper Cretaceous rocks appear to have entered the oil window in the Paleocene. In the Strahan Sub-Basin, mature Cretaceous sediments in the depocentres are available to traps, though considerable migration distances would be required.It is concluded that the west Tasmania margin, which has five strike-slip related depocentres and the potential to have generated and entrapped hydrocarbons, is worthy of further consideration by the exploration industry. The more prospective areas are the southern Otway Basin, and the Sandy Cape and Strahan sub-basins of the Sorell Basin.

Thermogenic hydrocarbons in surface sediments of the Bransfield Strait, Antarctic Peninsula

Antarctica is the only continent from which petroleum deposits have not been encountered, despite the occurrence of potential hydrocarbon basins onshore and around its margins. We have discovered thermogenic hydrocarbons in unconsolidated Recent sediments from the King George Basin, Bransfield Strait, west Antarctica. These sediments possessed a marked petroliferous smell throughout the length of the 8.6-m gravity core. The basin sediments are glacial marine deposits dominated by turbidites and contain abundant autochthonous organic matter as a result of high seasonal primary productivity in this most fertile part of the circumpolar ocean1. The maturation of this material into hydrocarbons may have been accelerated by the high geothermal gradient in the basin, associated with back-arc spreading created by the subduction of the Drake Plate into the South Shetland trench2. Sediments in this rifted basin are frequently intruded by volcanic sills and dykes3 giving rise to acoustic features shown in Fig. 1. The presence of these thermogenic hydrocarbons provides the first demonstration of active source rocks in Antarctica.

Hydrocarbon Entrapment in Alberta Deep Basin: ABSTRACT

Entrapment of hydrocarbon accumulations in the deepest region of the Alberta sedimentary basin is linked to certain principles of subsurface fluid flow behavior in generally tight sandstones, and to active hydrocarbon generation in adjacent source beds. Similar geologic conditions and associated deep-basin-type hydrocarbon accumulations no doubt exist in the deeper portions of other sedimentary basins. Conventional concepts of subsurface hydrocarbon accumulation do not apply to the deep basin form of entrapment, yet both mechanisms conform to certain important physical principles of fluid flow behavior. The conventional entrapment idea, based on many case histories and sound physical principles, entails downdip hydrocarbon-over-water contacts, initial reservoir pressures greater than formation water pressures at the same position (the so-called capillary displacement pressures), updip reservoir seals, and accumulations that are essentially in static equilibrium. Deep-basin concepts of hydrocarbon entrapment, on the other hand, are opposed to conventional ideas. Hydrocarbon-bearing sands in deep basin regions grade laterally updip into permeable water-bearing sands without reservoir barriers to segregate the fluids. Water-over-hydrocarbon contacts appear at the updip limits of the accumulations and generally are absent downdip. Original hydrocarbon accumulation pressures are usually less than projected formation-water pressures at common depth points. Deep-basin accumulations fed by active downdip source rocks may be in a dynamic state of slow, updip hydrocarbon migration. Hydrocarbons lost across the updip water/gas contact are replaced by new hydrocarbon influx from downdip source rocks. Prolonged hydrocarbon flux through deep-basin reservoi s may result in exceptionally low residual water saturations and favorable hydrocarbon relative permeabilities in tight sandstones. These unusual physical principles of the Alberta deep-basin hydrocarbon accumulations are illustrated by Elmworth field examples and by physical fluid flow models. End_of_Article - Last_Page 480------------