Early Cretaceous Source Rocks Research Articles

Tectonic–thermal evolution since the Mesozoic in the Suhongtu Depression, Yingen–Ejina Basin: Constraints from Apatite fission track and vitrinite reflectance

The Yingen–Ejina Basin (YEB) located in the western part of the North China Plate is a significant area for petroleum exploration. During the Early Cretaceous, the YEB witnessed the extensive development of source rocks. However, the subsequent tectonic evolution and multi‐stage thermal history of these source rocks have posed challenges to oil and gas exploration in the basin. This study focuses on the Mesozoic and Cenozoic tectonic evolution of the YEB, utilizing Apatite fission track (AFT) and vitrinite reflectance (Ro) data of samples from Well BC‐1 in the Suhongtu Depression, northern YEB. The central ages of six AFT samples ranged from 28 ± 2 to 49 ± 3 Ma with corresponding track lengths between 10.8 ± 1.9 and 12.3 ± 1.5 μm. Combining with the study of Ro and thermal history simulation, the thermal history of the YEB is summarized as follows: In the late Early Cretaceous, the study area experienced tectonic elevation, as evidenced by the discontinuous change in Ro values along the vertical column. Towards the end of the Late Cretaceous, there was a subsidence in the study area. The Ro data indicate that the Early Cretaceous source rocks, although experiencing several tectonic uplifts, had remained within the hydrocarbon generation temperature range, and reached the maximum thermal uplifts before the end of the Late Cretaceous. Therefore, hydrocarbon generation from early Cretaceous source rocks is an important exploration target in the study area and will be the focus of oil and gas exploration in the future.

Geochemical evaluation of Khami Group oils in the South Dezful Embayment, Iran

An integrated geochemical study, including GC, GC–MS and stable carbon isotope analyses, was conducted on a suite of oil samples from the Khami Group reservoirs to provide new insights into the Upper Jurassic–Lower Cretaceous petroleum system in the South Dezful Embayment. Possible source rocks were also characterized using Rock–Eval pyrolysis to address the likely potential source rocks. The oil samples representing four major reservoirs (Surmeh, Fahliyan, Gadvan and Dariyan) constitute a single genetic oil family according to bulk and biomarker parameters. High API (> 38°), highly saturated hydrocarbons (Sat > 65%), very low asphaltene content (Asp < 2%) and raised saturates/aromatics ratio (Sat/Aro > 2) are the bulk diagnostic characteristics of the studied oils implying more dominant terrigenous nature of the precursor organic matter. The predominance of C29 regular steranes (~ 40%), presence of C29Ts as well as very low gammacerane (< 10%) and moderate C35/C34 homohopane (< 1) are consistent with the mixed marine–terrigenous dysoxic organic matter input. The oils are assumed to be originated from Early Cretaceous source rocks at the peak of the oil generation window in a kitchen area located to the south of the studied region (i.e., the Binak–Borazjan Trough). The hydrocarbons were migrated from this kitchen to the structurally shallow-seated reservoirs in the center and west of the Kharg-Mish local paleo-high. The Khami Group reservoirs are not effectively sealed by the thin Hith anhydrites, and the Kazhdumi Formation finally trapped the migrated hydrocarbons. This study improves our knowledge regarding one of the active petroleum systems in the South Dezful Embayment, enhancing petroleum exploration success by navigating further drillings into the more prosperous targets.

Geochemical investigation of Yamama crude oils and their inferred source rocks in the Mesopotamian Basin, Southern Iraq

Ten oil samples from the Yamama reservoirs and ten extracts of purported source rocks from sixteen wells in the Mesopotamian Basin, Southern Iraq have been analyzed using GC, GC/MS and Stable Carbon Isotope. Yamama oils were non-biodegraded, moderate to higher maturity based on C27Ts of range from 0.17 to 0.77and TAS3 of 0.3 to 0.63, marine carbonate and marl source rocks, deposited under saline, anoxic conditions. Two oil groups were investigated based on the results of the geochemical analysis. These oils have similarly biomarkers ratios to those of the Middle Jurassic to Early Cretaceous source rocks in the Mesopotamian Basin.

Source rock characteristics of the Early Cretaceous Garau and Gadvan formations in the western Zagros Basin\u2013southwest Iran

Cretaceous source succession in the Zagros Basin comprises the Garau, Gadvan, and Kazhdumi formations, which have probably generated most of the oil and associated gas in the region. In the following study, the generation potential as well as maturity, molecular, and isotopic characteristics of the Early Cretaceous source rocks (Garau and Gadvan formations) in southwest Iran were investigated. One hundred and forty core and cutting samples of Early Cretaceous sediments were obtained from 24 wells in 12 oil fields from the northern Dezful Embayment and Abadan plain. Geochemical measurements such as Rock–Eval pyrolysis, vitrinite reflectance, GC, GC–MS, and isotopic studies were conducted on selected samples. The results have shown that the Gadvan Formation, with an average TOC of 0.65 wt% and HI values of 122 mgHC/g TOC, can be classified as poor source rock, while the Garau Formation, with TOC and HI values of up to 5.72 wt% and 413 mgHC/g TOC, respectively, can be considered as having good to excellent source potential. Kerogen in the Gadvan Formation belongs to Type III/II, while kerogen in the Garau Formation belongs to Type II. Samples from the Gadvan Formation are at the beginning of oil generation, while the current maturity of the Garau samples is already in the peak oil generation stage. Maturity in the studied samples increases eastward toward the Dezful Embayment. GC, GC–MS and isotopic values for the Gadvan Formation indicate high land plant contribution, low maturity, and oxic to sub-oxic depositional environment of the organic matter. In contrast, the Garau Formation shows an advanced level of maturity and marine depositional environment. Considering the results of this study, the Garau Formation, with excellent production potential and a high level of maturity, can be regarded as a source of a huge amount of oil and gas in the region.

Organic geochemistry characterisation of crude oils from Mishrif reservoir rocks in the southern Mesopotamian Basin, South Iraq: Implication for source input and paleoenvironmental conditions

Seven crude oils from Cretaceous Mishrif reservoir rocks in the southern Mesopotamian Basin, South Iraq were studied to describe oil characteristics, providing information on the source of organic matter input and the genetic link between oils and their potential source rock in the basin. This study is based on biomarker and non-biomarker analyses performed on oil samples. The analysed oils are aromatic intermediate oils as indicated by high aromatic hydrocarbon fractions with more that 50%. These oils are also characterized by high sulfur and trace metal (Ni, V) contents and relatively low API gravity values (19.0–27.2° API). The results of this study indicate that these oils were derived from a marine carbonate source rocks bearing Type II-S kerogen that were deposited under sulphate-reducing conditions. This is primary achieved from their biomarkers and bulk carbon isotope and inorganic element contents (i.e., S, Ni and V). The absence of 18a (H)-oleanane biomarker also suggests a source age older than Late Cretaceous. The biomarker characteristics of these oils are consistent with those of the Late Jurassic to Early Cretaceous source rocks in the basin. However, biomarker maturity data also indicate that the oils were generated from early maturity source rocks. This appears to result from the type of kerogen of the source rock, characterized by a high-S kerogen (Type II-S).

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

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

Evaluation of Hydrocarbon Generated and Expelled from the Jurassic to Early Cretaceous Source Rocks in the Lynedoch Field, Northern Bonaparte Basin, Australia

The Lynedoch field is located on the west flank of the Calder Graben in the north-eastern Bonaparte Basin, Australia. The data from the wells Lynedoch 1 and Lynedoch 2 and Seismic Line N11809 were used to reconstruct the burial and thermal histories and evaluate the hydrocarbon generated and expelled from the Jurassic to Early Cretaceous source rocks of the study area. Basin Mod 1-D and 2-D softwares were used for modeling. The Upper Jurassic Cleia (Lower Frigate) and Lower Cretaceous Echuca Shoals formations source rocks in the well Lynedoch 1 were a fair-to-good source richness with poor hydrocarbon generating potential, showing kerogen type III and gas prone. The Middle Jurassic Plover Formation source rock in the well Lynedoch 2 was a good organic matter richness with poor hydrocarbon generative potential, the late Middle Jurassic (Callovian) Elang Formation source rock in the same well was a fair source rock with poor hydrocarbon generation potential, and the Lower Cretaceous Echuca Shoals Formation source rock in the same well was a fair-to-very good organic richness with poor-to-fair hydrocarbon generating potential, gas prone with kerogen type III, and reaching wet gas window at present day. These previous formations of the both wells generated oil at the Late Cretaceous and gas at the Early Neogene. But, only Echuca Shoals Formation source rock in the well Lynedoch 2 was able to expelled hydrocarbon at the Middle Paleogene and continued up to present day. This Formation represents fair to slightly good potential source rock in the Lynedoch field.

Hydrocarbon sources of cold seeps off the Vesterålen coast, northern Norway

We investigated active methane seeps in a water depth of 200m in the Hola area off the coast of Vesterålen, northern Norway, to assess (1) hydrocarbon sources, (2) migration pathways and (3) the influence of hydrocarbon seepage on sediment pore water and water column chemistry. The seepage area is characterised by the presence of gas flares in the water column as revealed by hydro acoustic surveys and elevated methane concentrations of up to 42nM ca. 5m above the seafloor. Pore water analyses of three gravity cores from the seepage area show varying depths of the sulphate–methane-transition zone (SMTZ) between 80cm and >250cm indicating spatially heterogeneous methane ascent. The isotopic composition of methane (δ13C from −40‰ to −63‰ and δ2H from −191‰ to −225‰) and δ13C depth profiles of methane and dissolved inorganic carbon show that the hydrocarbons are predominantly of thermogenic origin, consistent with δ13C values of C2 to C4 hydrocarbons. Isotope data also indicate considerable biodegradation of propane. Seismic profiles from the study area reveal major faults and steeply dipping unconformities between the basement and overlying Mesozoic sedimentary rocks. We propose that these act as migration pathways for the hydrocarbons from late Jurassic to early Cretaceous source rocks.

Thermal History and Potential of Hydrocarbon Generated from Jurassic to Early Cretaceous Source Rocks in the Malita Graben, Northern Bonaparte Basin, Australia

The Malita Graben is located in the northern Bonaparte Basin, between the Sahul Platform to the northwest and the Petrel Sub-basin and Darwin Shelf to the south. The wells Beluga 1, Heron 1, Evans Shoal 1, Evans Shoal 2 and Seismic Line N11805 are selected to determine the thermal history and potential of hydrocarbon generated from the Plover, Elang, Frigate Shale (Cleia and Flamingo), and Echuca Shoals formations source rocks. The modeling was performed by using Basin Mod 1-D and 2-D techniques. The model results show that the geothermal gradients range from 3.05 to 4.05°C/100 m with an average of 3.75°C/100 m and present day heat flow values from 46.23 to 61.99 mW/m2 with an average of 56.29 mW/m2. The highest geothermal gradient and present-day heat flow values occurred on a terrace north of the Malita Graben. These most likely indicate that hot fluids are currently variably migrating into this structure. The lower geothermal gradient and heat flow values have been modeled in the southeast sites in the well Beluga 1. The northern Bonaparte Basin experienced several deformation phases including lithospheric thinning; hence, heat flow is expected to vary over the geological history of the basin. The higher paleo-heat flow values changing from 83.54 to 112.01 mW/m2 with an average of 101.71 mW/m2 during Jurassic rift event (syn-rift) were sufficient for source rocks maturation and hydrocarbon generation during Cretaceous post-breakup sequence (post-rift) in the study area. The Tuatara (Upper Frigate Shale) Formation source rock with type II & III kerogen dominantly showing mixed oil- and gas-prone, and Plover Formation with type III and gas prone have never reached the peak mature oil window in the well Beluga 1. This area indicates that the maturity of source rocks is low and considered to be from poor-to-good organic richness with poor-to-fair potential for hydrocarbons generation. The post mature Cleia (Lower Frigate Shale) and Echuca Shoals formations source rocks in the well Evans Shoal 1 and an early mature oil window Echuca Shoals formation source rock in the well Evans Shoal 2, characterized by type III kerogen dominantly showing gasprone are a fair-to-very good source richness with poor potential for hydrocarbons generation. The low to high maturity of Echuca Shoals and Petrel (Frigate Shale) formations source rocks in the well Heron 1, Plover Formation source rock in the Evans Shoal 1 well, and Cleia (Lower Frigate Shale) and Plover formations in the well Evans Shoal 2, showing gas-prone with type III and II & III kerogens predominantly, have reached the late mature oil and wet gas generation stages at present day. These last five formations source rocks are seen from poor-to-very good organic richness with poor-to-very good potential for hydrocarbons generation in the Malita Graben.

Distribution and origin of natural gas leakage in the Colorado Basin, offshore Argentina Margin, South America: seismic interpretation and 3D basin modelling

The detailed analysis of a dense 2D seismic reflection dataset and data from 8 exploration wells, allowed us to identify, map out and characterize possible indications of past and present-day hydrocarbon leakage (i.e. gas chimneys, gas pockets, and seafloor mounds and pockmarks) on the continental shelf and slope of the Colorado Basin, offshore Argentina, where Permian, Jurassic and Early Cretaceous source rocks are potentially present and may be currently mature. Identified gas leakage features, developed both in the syn-rift and post-rift successions, were also analysed in relation to the structural the stratigraphic elements of the basin. A family of seabed pockmarks, located close to an array of submarine channels, was identified on the distal slope of the basin. These pockmarks are overlying a series of sub-vertical to vertical seismic chimneys in the subsurface. A calibrated basin-wide 3D petroleum system model comprising generation and migration of hydrocarbons was carried out and compared with the observations from the seismic analysis. Preliminary results from this model indicate that although synrift and early Cretaceous source rock (SR) intervals may be depleted in the central areas of the basin, an active kitchen from the Aptian SR may be present below the slope areas. Hydrocarbon migration pathways predicted by the 3D model (Hybrid method) coincide with the interpreted seismic chimneys underlying the observed seabed slope pockmarks. Hence, our results indicate that thermogenic gas may be currently generated in the distal slope of the basin from mature early post-rift source rocks within the Early Cretaceous (Aptian) sequences and migrates vertically, due to seal failure, through the stratigraphic column. This migrating thermogenic gas is feeding the seafloor pockmarks identified in the distal slope of the basin, although up-dip lateral migration along stratigraphic layers to the more proximal slope areas cannot be ruled out. The present work represents the first published study integrating detailed seismic analysis and 3D basin modelling linking observed gas-leakage indicators and associated seepage pathways, to their relative abundance, distribution and feeding systems offshore Argentina’s continental margin.

Organic Petrology Study of the Early Cretaceous Source Rocks in Weichang, Chifeng Basin

Organic petrology method is applied to analysis hydrocarbon potential of early Cretaceous source rocks in Hebei Weichang, Chifeng basin. Conclusions are drawn as follows: Organic Maceral is mainly pieces of vitrinite, liptinite consists algae and small spores; organic matter abundance is better; organic type isI-II1, in an immature stage which currently does not have potential for bearing hydrocarbon.

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

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

Impacts of Neogene-Recent compressional deformation and uplift on hydrocarbon prospectivity of the passive southern Australian margin

The passive southern margin of the Australian continent, which formed following Cretaceous–Palaeogene separation from Antarctica, contains a rich record of Neogene–Recent compressional deformation and uplift. This deformation and uplift is manifested by reversal of displacement along syn-rift extensional faults, folding of mid–late Cenozoic post-rift sediments, and regional unconformities that can be traced for distances of up to 1,500 km along the margin. Palaeothermal data from onshore and offshore exploration wells indicate that erosion associated with deformation and uplift locally exceeds 1 km in the eastern Otway Basin. Both neotectonic palaeostress trends inferred from these structures and present-day stress orientations are consistent with northwest–southeast directed compression controlled to first-order by plate boundary forces. The critical role of the relative timing of trap formation and source rock maturation in controlling hydrocarbon prospectivity in the southern Australian margin is investigated by comparing two structures that formed during Neogene–Recent deformation in the Otway Basin: the Minerva and Nerita anticlines. While the Minerva Anticline hosts a major gas field (558 BCF GIP), the Nerita Anticline was found to be dry. A combination of apatite fission track analysis (AFTA), vitrinite reflectance (VR) and present-day temperature data show that all units intersected in Minerva–1 are presently at their maximum post-depositional temperatures, and are presently mature for hydrocarbon generation. In contrast, similar data collected from the preserved section at Nerita–1 indicate cooling from maximum post-depositional temperatures prior to formation of the Nerita Anticline in the late Miocene. Based on regional AFTA data, the underlying early Cretaceous source rocks probably reached maximum palaeotemperatures and ceased hydrocarbon generation during mid-Cretaceous uplift. These results indicate that areas of the southern margin that were deformed during the Neogene–Recent have the greatest potential to trap hydrocarbons where potential source rocks are presently at their maximum post-depositional temperatures.

Play fairways of the Gulf of Guinea transform margin

Abstract The margin between Côte d’Ivoire and the Niger Delta is a region with a common structural history, this being reflected in similarities in the stratigraphic response and play fairways identified across the region. There has been significant exploration on the narrow shelf characterizing the margin, resulting in a series of modest oil and gas discoveries. It is shown in this paper that many of the aspects of the plays in the unexplored deep-water regions of the margin are considerably more favourable to the development of giant fields than those on the shelf. This play-fairway review is based on the integration of existing publications with focused studies of multiclient 3-D seismic data over a number of areas. Play fairways are classified by seismic sequence and trap type, with an analysis of each undertaken. The most attractive deep-water play types are: (1) anticlinal traps involving late syn-transform (Apto-Albian) and early post-transform (Late Cretaceous) reservoirs, (2) combination traps involving ponded turbidites on the shoreward flanks of these highs, and (3) stratigraphic traps associated with large Late Cretaceous submarine fan complexes. The anticlinal play is associated with the terminations of the St Paul and Romanche fracture zones, with the more recent structuring generally associated with the latter. 3-D imaging and amplitude mapping is critical to prospect delineation, particularly for the combination and stratigraphic plays. Active kitchens are evidenced involving Early and Late Cretaceous source rocks in the Côte d’Ivoire and western Ghana to Nigeria segments of the region, which are consequently upgraded. Considerable volumetric potential is indicated that promises to make the region one of significant new exploration activity in coming years.

Abstract: Early Cretaceous Rift Source Rocks from Eastern Brazilian Margin: Isotopic and Molecular Correlation

Abstract: Early Cretaceous Rift Source Rocks from Eastern Brazilian Margin: Isotopic and Molecular Correlation

KITCHENS, KETTLES AND CUPS OF HYDROCARBONS, VICTORIAN OTWAY BASIN

Evaluation of Early Cretaceous source rocks within the onshore Victoria Otway Basin has revealed that thick, mature shales containing predominantly gas-prone and in local concentrations, oil-prone macerals exist northwest of Portland, in the Tyrendarra Embayment, and around the Port Campbell region.Current results of Rock-Eval, bulk composition, gas chromatography, and biomarker analyses, coupled with geohistory and hydrocarbon generation interpretations, indicate that at least three phases of oil generation and expulsion occurred within the basin. The earliest phase, which coincided with the maximum heatflow in the crust around 100 Ma, resulted in the charging of the existing stratigraphic/shoestring traps of the basin. The second and third phases occurred in the eastern end of the basin at around 85 and 60 Ma. There is also evidence to suggest that structural traps of the eastern areas were formed later, during Oligocene time, and that these traps are probably still receiving late-stage charges of hydrocarbons.Although the sparse well density in the basin has resulted in limited, non-uniforin sampling opportunities, several regions with good Early Cretaceous source rocks can be recognised. Some of these good source rock areas are in close proximity to the several known hydrocarbon shows and producing fields. These current studies, which also include a source rock risk analysis indicating source rock adequacy, show that locations for future exploration could include the Casterton-Portland-Mt Gambier western region, the Peterborough-Port Campbell eastern region, and the prospective close peripheries and offshore extensions of these regions.

Hydrocarbons Related to Early Cretaceous Source Rocks, Reservoirs and Seals, Trapped In Northeastern Neuqun Basin, Argentina: ABSTRACT

The Jurassic-Cretaceous backarc Neuqun Basin, located in the west central part of Argentina, is currently the most prolific oil basin of the country. The primary objective of this study is to evaluate an Early Cretaceous to Tertiary petroleum system in the northeastern portion of the basin, where oil and gas occurrences (e.g., Puesto Hernandez, Chihuido de la Sierra Negra, El Trapial and Filo Morado oil fields, among others) provide 82 MMBO/yr comprising 67% of the basin oil production and 31% of Argentina. The source rocks are represented by two thick sections of basinal kerogen type I and II organic-rich shales, deposited during transgressive peaks (Agrio Formation), with TOC content up to 5.1%. Lowstand sandstones bodies, 10 to 100 m thick, are composed of eolian and fluvial facies with good reservoir conditions (Avil and Troncoso Sandstones). The seals are provided by the organic-rich shales resting sharply upon the Avil Sandstone and a widespread Aptian-Albian evaporitic event (Huitrin Formation) on top of the Troncoso reservoir. Tertiary structural traps (duplex anticlines) are developed in the outer foothills, whereas structural, combined and stratigraphic traps are present in the adjacent stable structural platform. Oil-to-source rock and oil-to-oil correlation by chromatographic and biomarker fingerprints, carbon isotopicmore » composition and the geological evidences support the proposed oil system.« less

Romania's Petroleum Systems

In Romania, nine onshore petroleum systems and one offshore petroleum system have recently been identified. Of the onshore systems, three are related to the compressional folded basins: Teleajen-Sita (early Middle Cretaceous marine source rocks), and Puciossa-Fusaru and Alunis-Kliwa (Oligocene-early Miocene marine source rocks). In the same category, we have included the recently discovered Deleni petroleum system with source rocks of not yet identified origin but whose reservoirs certainly belong to a folded basin. In the foreland platform basins, two systems can be distinguished: Rimesti-Fauresti (Middle Jurassic marine source rocks) and Infra-Anhydrite (with presumed Middle Jurassic or middle Miocene marine source rocks). The areas corresponding to the posttectonic basins include three onshore petroleum systems and one offshore system: the Pannonian (Badenian marine and Sarmatian brackish water source rocks), the Valea Caselor-Borsa (oligocene marine source rocks) and the Transylvanian (Badenian marine shales source and Sarmatian brackish water source rocks). Offshore, there is only one petroleum system consisting of Oligocene-Miocene marine source rock and Cretaceous or Eocene reservoirs. The majority of the mentioned petroleum systems reservoirs are Paleozoic to Pliocene clastics, but in the platform areas, carbonate reservoirs are found in the Paleozoic and Mesozoic. In all the petroleum systems, despite the differentmore » ages of the source rocks, most of the hydrocarbons have been expelled relatively recently during the Late Sarmatian-Pliocene interval. This face is substantiated by examples from two petroleum systems: the Rimesti-Fauresti (duration time 173 m.y., preservation 2 m.y.) and the Alunis-Kliwa (duration time 29-30 m.y., preservation 4 m.y.). The hydrocarbons were first expelled and migrated into described systems reservoirs after Late Styrian and Moldavian overthrusting, i.e. not earlier than 12-14 m.y.« less

Geochemistry of the Hydrocarbons from the Orinoco Belt: Eastern Venezuela Basin

A regional study has been performed on the heavy crude oils and bitumens from the Orinoco belt in the Eastern Venezuela Basin. The geochemical characterization of these hydrocarbons has been achieved using biological marker compounds including steranes, triterpanes, aromatic steroids and phenantrenes (GC-MS techniques) and petroporphyrins (analyzed by HPLC) as well as general parameters (S.A.R.A. composition, GC results, API gravity, etc.) determined in previous work. The heavy crudes oils and bitumens originated from early mature Cretaceous source rocks located at the North of the basin and are the result of severe biodegradation processes and accumulation in shallow reservoirs. Biodegradation shows different patterns according to the type of location (surface or subsurface). The classification of these hydrocarbons in terms of biodegradation was further complicated by the identification of mixed oils, which include most of the crude oils and bitumens in the Orinoco Belt with API gravities higher than 9-10 API. The crudes and bitumens from the Cerro Negro, Hamaca, and eastern Zuata areas seem to have been generated from the same source, while those of the Machete and western Zuata seem to have been generated from a different source rock. Furthermore, the Machete area oils and bitumens seem to be generatedmore » from source rocks at lower maturity stages.« less