Vitrinite Reflectance Measurements Research Articles

Geologic controls on thermal maturity patterns in Pennsylvanian coal-bearing rocks in the Appalachian basin

Thermal maturation patterns of Pennsylvanian strata in the Appalachian basin were determined by compiling and contouring published and unpublished vitrinite reflectance (VR) measurements. VR isograd values range from 0.6% in eastern Ohio and eastern Kentucky (western side of the East Kentucky coal field) to greater than 5.5% in eastern Pennsylvania (Southern Anthracite field, Schuylkill County), corresponding to ASTM coal rank classes of high volatile C bituminous to meta-anthracite. VR isograds show that thermal maturity of Pennsylvanian coals generally increases from west to east across the basin. The isograds patterns, which are indicative of maximum temperatures during burial, can be explained by variations in paleodepth of burial, paleogeothermal gradient, or a combination of both. However, there are at least four areas of unusually high-rank coal in the Appalachian basin that depart from the regional trends and are difficult to explain by depth of burial alone: 1) a west-northwestward salient centered in southwestern Pennsylvania; 2) an elliptically-shaped, northeast-trending area centered in southern West Virginia and western Virginia; 3) the eastern part of Black Warrior coal field, Alabama; and 4) the Pennsylvania Anthracite region, in eastern Pennsylvania. High-rank excursions in southwest Pennsylvania, the Black Warrior coal field, and the Pennsylvania Anthracite region are interpreted here to represent areas of higher paleo-heat flow related to syntectonic movement of hot fluids towards the foreland, associated with Alleghanian deformation. In addition to higher heat flow from fluids, the Pennsylvania Anthracite region also experienced greater depth of burial. The high-rank excursion in southwest Virginia was probably primarily controlled by overburden thickness, but may also have been influenced by higher geothermal gradients.

Evaluating maturity of source rocks by aromatic compounds: A case from Dongling Block, Songliao Basin

Abstract The characteristics of the thermal evolution of aromatic maturity parameters, such as methyl phenanthrene, alkylated dibenzothiophene, dehydroxy-tocopherol and triaromatic-sterane series compounds are discussed on the basis of molecular organic geochemistry and GC-MS analysis of the source rocks in the Dongling area of the Songliao Basin. The distribution characteristics of aromatic hydrocarbon chromatography, the methyl phenanthrene index (MPI), the ratio of β/γ dehydroxy-tocopherol, 4-/1-MDBT, 4,6-/1,4-DMDBT, TASC27 (20R)/C28 (20R), the content of the triaromatic-sterane series and vitrinite reflectance measurements all suggest that the Lower Cretaceous Quantou Formation source rock is in the middle stage of maturity, whereas the Lower Cretaceous Yingcheng Formation and the Upper Jurassic Huoshiling Formation source rocks have reached a high maturity stage.

Thermal basin modelling of the Arauco forearc basin, south central Chile — Heat flow and active margin tectonics

The Arauco basin is part of the coastal forearc domain in South-Central Chile. During its evolution since the Late Cretaceous it was subject to multiple deposition cycles and the erosion of lower bathyal to beach and lagoon sediments. These different environments were established in alternating accretional and erosive subduction tectonic settings along the South Andean active margin. Whereas the general development is well understood, inconsistencies arise regarding the origin of the high thermal maturity of Eocene coals and the estimates of vertical movements of the whole area during the Cenozoic. Thermal modelling of this forearc basin provides new insights regarding its thermal evolution and evaluation of the magnitudes of subsidence and inversion. Results are based on the analysis of coal samples from surface outcrops, mines and drill cores of ten onshore wells from ENAP/Sipetrol. Newly derived vitrinite reflectance (VR r) measurements indicated a temperature in the range of 135–150 °C for the oldest sediment unit of the Arauco basin, which was reached in post Eocene times. Furthermore, 1D basin modelling techniques indicate scenarios that could explain the coalification values in the basin's sediments. The models were calibrated against VR r data from drill core samples supplied by ENAP/Sipetrol. A Miocene and an Oligocene subsidence/inversion scenario were considered, while neither could be securely discarded based on the modelling results. Furthermore, it can be shown that the current thermal maturity was not reached by an increased heat flow (HF) or a deep subsidence only. Consequently, a structural inversion accompanied by the erosion of ~ 3.0 ± 0.4 km depending on the locality in combination with a high HF of ~ 64 ± 4 mW/m 2 is the best explanation of the available data. The HF, which is high for a forearc setting, can be attributed to the increased temperature of the relatively young subducted Nazca Plate and an additional influence of ascending hot fluids from the subduction zone. The maximum temperature gradient inferred is < 30 °C/km. Furthermore, the petroleum generation potential of the basin is considered to be rather low based on our results.

Paleo-heat flow evolution of the Tabei Uplift in Tarim Basin, northwest China

The paleo-heat flow evolution of the Tabei Uplift in the Tarim Basin is investigated based on burial and thermal history reconstruction of 14 wells and using basin modeling. Numerous geological parameters, such as, temperature data and missing sediment thickness by erosion were used in the modeling. The basin model was calibrated using 460 measured vitrinite reflectance (% VR o) and vitrinite-like maceral reflectance (% VLMR o) values to constrain the validity of the maturity model. The heat flow history of the Tabei Uplift, Tarim Basin shows the following characteristics: (1) the highest paleo-heat flow was predicted to have occurred in the Early Ordovician as 65 ± 5 mW/m 2, and gradually decreased to 55 ± 5 mW/m 2 during the Late Carboniferous; (2) a thermal kick was modeled to have occurred in the Permian as suggested by an abrupt rise in the heat flow; (3) the heat flow gradually decreased since the Triassic; (4) the present day heat flow was predicted to be as low as 38 mW/m 2. This heat flow history honors the geologic and tectonic evolution history of the Tabei Uplift and is suggested as the best case heat flow model.

Composition, peat-forming vegetation and kerogen paraffinicity of Cenozoic coals: Relationship to variations in the petroleum generation potential (Hydrogen Index)

Coals with similar thermal maturity and from the same deposit normally show a considerable range in petroleum generation potential as measured by the Hydrogen Index (HI). This variation may partly be related to variations in plant input to the precursor mires and organic matter preservation. It is widely accepted that some Cenozoic coals and coaly sediments have the potential to generate oil, which is related to the coal's paraffinicity. Coal paraffinicity is not readily reflected in the bulk HI. In this paper, the relationships between measured HI and coal composition, coal kerogen paraffinicity and floral input have been investigated in detail for three sets of coals from Colombia/Venezuela, Indonesia, and Vietnam. The samples in each coal set are largely of iso-rank. The petroleum generation potential was determined by Rock–Eval pyrolysis. Reflected light microscopy was used to analyse the organic matter (maceral) composition and the thermal maturity was determined by vitrinite reflectance (VR) measurements. The botanical affinity of pollen and spores was analysed by palynology. Coal kerogen paraffinicity was determined by ruthenium tetroxide-catalysed oxidation (RTCO) followed by chain length analysis and quantification (mg/g TOC) of the liberated aliphatic chains. The coals are dominated by huminite, in particular detrohuminite. Only the Vietnamese coals are rich in microscopically visible liptinite. The pollen and spores suggest that the coals were derived principally fromcomplex angiospermmire vegetations, with subordinate proportions of ferns that generally grew in a subtropical to tropical climate.Measured HI values vary considerably, but for the majority of the coals the values lie between approximately 200 mg HC/g TOC and 300 mg HC/g TOC. Aliphatics yielding monocarboxylic acids dominate in the coal kerogen, whereas aliphatics yielding dicarboxylic acids are secondary. However, the dicarboxylic acids show that crosslinking long-chain aliphatics are present in the kerogen structure. All studied coals are paraffinicwith C19–35 aliphatic chains in the kerogen, and the aliphatics in the range C25–35 show that the coals may have the potential to generate waxy crude oil. The Indonesian coals are richest in long-chain aliphatics and are thus potentially most oil-prone. Multivariate statistical analysis shows that for the present three sample sets variations in HI are positively correlated to different combinations of the C10+ aliphatic chains in the kerogen and the amount of detrohuminite + liptodetrinite and liptinite. Furthermore, part of the HI can be attributed to hydrogen in compounds with less than 10 carbon atoms, which is the lowest alkyl detected by RTCO analysis, thus representing a potential for generation of gas and light liquid hydrocarbons. The measured HI is therefore not always a good indicator for humic coal's potential to source waxy oil. Vegetational influence (palynology) on the variation of HI cannot be shown within the investigated span of variance and for the present coals. However, it is likely that some of the range in measured HI values is caused by floral vairiations not revealed by the palynological analysis and to variations in the preservation of the organic matter. (Less)

Hydrocarbon potential of the Barnett Shale (Mississippian), Delaware Basin, west Texas and southeastern New Mexico

The Barnett Shale (Mississippian) in the Delaware Basin has the potential to be a prolific gas producer. The shale is organic rich and thermally mature over large parts of the basin. Depths to the Barnett range from 7000 ft (2133 m) along the western edge of the basin to more than 18,000 ft (5486 m) along the basin axis. The Barnett Shale began generating petroleum about 250 Ma and reached its maximum temperature about 260 Ma. Present-day thermal maturity is indicative of maximum burial and temperature. Wells in northern Reeves County are in the gas window based on measured vitrinite reflectance values and kerogen transformation ratios. The shale can be divided into an upper clastic unit and a lower limy unit by changes in resistivity. The lower unit can be subdivided into five subunits by distinctive well-log markers. Preliminary analyses suggest that intervals in the lower Barnett marked by high resistivity and high neutron porosity readings on well logs have high gas contents. Areas in which to focus the future exploration in the lower Barnett can be delineated by mapping a net resistivity greater than 50 ohm m. The Barnett Shale contains significant gas resources in the Delaware Basin. Realizing the potential of these resources depends on the current efforts to optimize drilling and completion techniques for this shale-gas play.

COMPOSITION AND PETROLEUM POTENTIAL OF LAKE FACIES IN THE FA‐MS‐48‐73 WELL, MAE SOON STRUCTURE, FANG OILFIELD, NORTHERN THAILAND

The Fang Basin is one of a series of Cenozoic rift‐related structures in northern Thailand. The Fang oilfield includes a number of structures including the Mae Soon anticline on which well FA‐MS‐48‐73 was drilled, encountering oil‐filled sandstone reservoirs at several levels. Cuttings samples were collected from the well between depths of 532 and 1146 m and were analysed for their content of total organic carbon (TOC, wt%), total carbon (TC, wt%) and total sulphur (TS, wt%); the petroleum generation potential was determined by Rock‐Eval pyrolysis. Organic petrography was performed in order to determine qualitatively the organic composition of selected samples, and the thermal maturity of the rocks was established by vitrinite reflectance (VR) measurements in oil immersion. The TOC content ranges from 0.75 to 2.22 wt% with an average of 1.43 wt%. The TS content is variable with values ranging from 0.12 to 0.63 wt%. Rock‐Eval derived S1 and S2 yields range from 0.01–0.20 mg HC/g rock and 1.41–9.51 mg HC/g rock, respectively. The HI values range from 140 to 428 mg HC/g TOC, but the majority of the samples have HI values &gt;200 mg HC/g TOC and about one‐third of the samples have HI values above 300 mg HC/g TOC. The drilled section thus possesses a fair to good potential for mixed oil/gas and oil generation. On an HI/Tmax diagram, the organic matter is classified as Type II and III kerogen. The organic matter consists mainly of telalginite (Botryococcus‐type), lamalginite, fluorescing amorphous organic matter (AOM) and liptodetrinite which combined with various TS‐plots suggest deposition in a freshwater lacustrine environment with mild oxidising conditions. Tmax values range from 419 to 436°C, averaging 429°C, and VR values range from ∼0.38 to 0.66% R0, indicating that the drilled source rocks are thermally immature with respect to petroleum generation. The encountered oils were thus generated by more deeply buried source rocks.

Chemical and petrographical characterization of feed coal, fly ash and bottom ash from the Figueira Power Plant, Paraná, Brazil

Abstract The aim of the present study is the petrographic and chemical characterization of the coal at the Figueira Power Plant, Parana, Brazil, prior and after the beneficiation process and the chemical characterization of fly and bottom ashes generated in the combustion process. Petrographic characterization was carried out through maceral analysis and vitrinite reflectance measurements. Chemical characterization included proximate analysis, determination of calorific value and sulphur content, ultimate analysis, X-ray diffraction, X-ray fluorescence, Inductively Coupled Plasma — Mass Spectrometry (ICP-MS) and Inductively Coupled Plasma — Atomic Emission Spectrometry (ICP-AES) analysis, and determination of Total Organic Carbon (TOC) content. Vitrinite reflectance analyses indicate a high volatile B/C bituminous coal (0.61 to 0.73% Rrandom). Maceral analyses show predominance of the vitrinite maceral group (51.6 to 70.9 vol.%, m.m.f). Except of the Run of mine (ROM) coal sample, the average calorific value of the coals is 5205 kcal/kg and ash yields range from 21.4 to 38.1 wt.%. The mineralogical composition (X-ray diffraction) of coals includes kaolinite, quartz, plagioclase and pyrite, whereas fly and bottom ashes are composed by mullite, ettringite, quartz, magnetite, and hematite. Analyses of major elements from coal, fly and bottom ashes indicate a high SiO 2 , Al 2 O 3 , and Fe 2 O 3 content. Trace elements analysis of in-situ and ROM coals by ICP-MS and ICP-AES show highest concentration in Zn and As. Most of the toxic elements such as As, Cd, Cr, Mo, Ni, Pb, and Zn are significantly reduced by coal beneficiation. Considering the spatial distribution of trace elements in the beneficiated coal samples, which were collected over a period of three months, there appears to be little variation in Cd and Zn concentrations, whereas trace elements such as As, Mo, and Pb show a larger variation. In the fly and bottom ashes, the highest concentrations of trace elements were determined for Zn and As. When compared with trace element concentrations in the feed coal, fly ashes show a significant enrichment in most trace elements (As, B, Be, Cd, Co, Cr, Cu, Li, Mn, Mo, Ni, Pb, Sb, Tl, and Zn), suggesting a predominantly volatile nature for these elements. In contrast, Sn is distributed evenly within the different ash types, whereas U shows depleted concentration in both bottom and fly ash samples. According to the International Classification of in-seam coals the Cambui coals are of para/ortho bituminous rank of low grade (except for the ROM sample), and are characterized by the predominance of vitrinite macerals.

Application of integrated vitrinite reflectance and FAMM analyses for thermal maturity assessment of the northeastern Malay Basin, offshore Vietnam: Implications for petroleum prospectivity evaluation

Several exploration wells have intersected a Cenozoic coal-bearing, fluvial-deltaic mudstone and sandstone succession in the northeastern Vietnamese part of the Malay Basin, and have successfully tested seismically identified direct hydrocarbon indicators (DHIs). The oil and gas/condensate discovery well 46-CN-1x encountered a ∼55 m thick section of lacustrine mudstones having considerable potential as an oil source. Vitrinite reflectance (VR) measurements from these alginite-bearing rocks introduce several problems in thermal maturity evaluation, including associated VR suppression and delineation of cavings and bitumens. Reliable thermal maturity gradients, however, may be established using a combination of conventional VR measurements and ‘equivalent VR’ (EqVR) values derived from the fluorescence alteration of multiple macerals (FAMM) technique. These measurements, performed on dispersed organic matter (DOM) in cuttings from 46-CN-1x, allow separation of low-reflecting bitumens and vitrinite in cavings from indigenous vitrinite and the FAMM results indicate VR suppression of 0.14% in an alginite-bearing mudstone with a high Hydrogen Index value. On the basis of available ‘raw’ VR data, a highly irregular maturity trend is determined, with the deepest sample (2675–2680 m) having a VR of ∼0.4%R o. The EqVR value, however, for the deepest sample is 0.70%. The maturity trend determined from the FAMM data (and VR data, omitting samples having suppressed VR) indicates that the top of the oil window (VR of 0.75%R o) is located at about 2800 m depth. Modelling the geothermal gradient using the EASY%R o algorithm yields ∼40 °C/km for both of the two maturity profiles; this is in the low end of the range for the Malay Basin. Modelled temperature histories indicate onset of hydrocarbon generation for the uppermost Oligocene source rocks between 2 Ma and present-day, which post-dates trap formation. Seismic facies patterns suggest that lacustrine oil-prone units are in the oil window in the same graben complex a few km NW of the investigated well, and these rocks are likely to be the source of the hydrocarbons found in the well. A more widespread occurrence of hydrocarbons sourced from this kitchen is indicated by other discoveries and mapping of DHIs in the area.

Black shale formation in the late Paleocene/early Eocene Arctic Ocean and paleoenvironmental conditions: New results from a detailed organic petrological study

The study of particulate organic matter (OM) in Arctic Ocean sediments from the late Cretaceous to the Eocene (IODP Expedition 302) has revealed detailed information about the aquatic/marine OM fluxes, biological sources, preservation and export of terrestrial material. Here, we present detailed data from maceral analysis, vitrinite reflectance measurements and organic geochemistry. During the Campanian/Paleocene, fluxes of land-derived OM are indicated by reworked and oxidized macerals (vitrinite, inertinite) and terrigenous liptinite (cutinite, sporinite). In the early Eocene, drastic environmental changes are indicated by peaks in aquatic OM (up to 40–45%, lamalginite, telalginite, liptodetrinite, dinoflagellate cysts) and amorphous OM (up to 50% bituminite). These events of increased aquatic OM flux, similar to conditions favoring black shale deposition, correlate with the global δ 13C events ‘Paleocene/Eocene Thermal Maximum’ (PETM) and ‘Elmo event’. Freshwater discharge and proximity of the source area are documented by freshwater algae material ( Pediastrum, Botryococcus) and immature land-plant material (corphuminite, textinite). We consider that erosion of coal-bearing sediments during transgression time lead to humic acids release as a source for bituminite deposited in the early Eocene black shales.

GEOCHEMICAL CHARACTERIZATION OF POTENTIAL JURASSIC/CRETACEOUS SOURCE ROCKS IN THE SHUSHAN BASIN, NORTHERN WESTERN DESERT, EGYPT

Some 180 core and cuttings samples of shales and limestones from the Middle Jurassic – Late Cretaceous succession (Khatatba, Masajid, Alam El‐Bueib, Alamein, Kharita, Bahariya and Abu Roash Formations) were collected from wells Ja 27–2, Tarek‐1 and Jb 26–1 in the central, structurally‐low part of the Shushan Basin and from well Lotus‐1 in the structurally‐elevated western part of the basin. All samples were screened for total organic carbon (TOC) content. Selected samples were then analyzed by Rock‐Eval pyrolysis, and extracted for biomarker analyses. Visual kerogen analysis and vitrinite reflectance measurements were also undertaken and oil ‐ source rock correlations were attempted. The results indicate that the thermal maturity of the samples can be correlated closely with burial depth. Samples from the central part of the basin are more mature than those from the west. Samples from the central part of the basin (except those from the Albian Kharita Formation) have reached thermal maturities sufficient to generate and expel crude oils. Extracts from the Middle Jurasic Khatatba and Early Cretaceous Alam El‐Bueib Formations can be correlated with a crude oil sample from well Ja 27–2.In well Lotus‐1 in the west of the basin, four distinct organic facies can be recognized in the Jurassic‐Cretaceous interval. One of the facies (“facies 4”) has a sufficiently high TOC content to act as a source rock. Thermal maturities range from immature to peak oil generation, and the top of the oil window occurs at approximately 8000 ft.

Relationships between Organic Material and Thermal Maturity Derived from Coal and C-Shale Samples

The purpose of this study is to characterize the relationship between organic material and thermal maturity during the process of evaluation of hydrocarbon potential. Samples studied include Miocene high volatile bituminous coal and coaly shale collected from outcrops and exploration wells in Hsinchu-Miaoli area, NW Taiwan, density centrifuge separated macerals, bituminous coal and anthracite from China, in addition to Woodford and Green River oil shale from the United States. Maceral composition analysis, elemental analysis, vitrinite reflectance measurement and Rock-Eval pyrolysis were performed for evaluation. The results of study show that: 1) coal samples from the Shiti Formation (middle Miocene) exhibit more vitrinite and less mineral matter contents than samples from the Nanchuang Formation (upper Miocene); H% is increased in exinite-enriched maceral mixtures with density ＜1.25 g cm^(-3), after density centrifuge separation. 2) A positive linear correlation between Tmax and Ro illustrates both Rock-Eval pyrolysis and vitrinite reflectance can be used as indicators of thermal maturity. 3) From the plot of H/C ratio vs. vitrinite reflectance, even though the depositional environments were different in Taiwan and China, their organic micelles exhibit a similar trend in the process of thermal maturation. As a whole, the curve has a turning point at Ro=0.5% and H/C=0.1 (atomic ratio 1.2) in this study. 4) Arather good correlation between S2 and TOC of samples studied indicates the contribution of S2 from TOC. 5) The highest HI occurred in certain maturities (Tmax and Ro) of samples studied, and not in the stages of less maturity or over-maturity. 6) Two different linear trends were observed in the cross plot of S1 vs. S2. Field outcropped shale or C-shale exhibits a steeper slope compared to that of coal samples which can be attributed to the compositional difference in their organic material. 7) A rather strong positive correlation for H% vs. S2 illustrates the contribution of H-containing macerals, especially exinite. As a result of this study, we expect to promote evaluation techniques for HC exploration; for instance, the development or improvement of evaluation methods for source rocks, reservoirs, structural evolution, and thermal maturity. Evaluations are expected to give more detail regarding local conditions, and be better quantified and more accurate.

SOURCE ROCK POTENTIAL OF THE BLUE NILE (ABAY) BASIN, ETHIOPIA

The Blue Nile Basin, a Late Palaeozoic ‐ Mesozoic NW‐SE trending rift basin in central Ethiopia, is filled by up to 3000 m of marine deposits (carbonates, evaporites, black shales and mudstones) and continental siliciclastics. Within this fill, perhaps the most significant source rock potential is associated with the Oxfordian‐Kimmeridgian Upper Hamanlei (Antalo) Limestone Formation which has a TOC of up to 7%. Pyrolysis data indicate that black shales and mudstones in this formation have HI and S2 values up to 613 mgHC/gCorg and 37.4 gHC/kg, respectively. In the Dejen‐Gohatsion area in the centre of the basin, these black shales and mudstones are immature for the generation of oil due to insufficient burial. However, in the Were Ilu area in the NE of the basin, the formation is locally buried to depths of more than 1,500 m beneath Cretaceous sedimentary rocks and Tertiary volcanics. Production index, Tmax, hydrogen index and vitrinite reflectance measurements for shale and mudstone samples from this areas indicate that they are mature for oil generation. Burial history reconstruction and Lopatin modelling indicate that hydrocarbons have been generated in this area from 10Ma to the present day.The presence of an oil seepage at Were Ilu points to the presence of an active petroleum system. Seepage oil samples were analysed using gas chromatography and results indicate that source rock OM was dominated by marine material with some land‐derived organic matter. The Pr/Ph ratio of the seepage oil is less than 1, suggesting a marine depositional environment. n‐alkanes are absent but steranes and triterpanes are present; pentacyclic triterpanes are more abundant than steranes. The black shales and mudstones of the Upper Hamanlei Limestone Formation are inferred to be the source of the seepage oil.Of other formations whose source rock potential was investigated, a sample of the Permian Karroo Group shale was found to be overmature for oil generation; whereas algal‐laminated gypsum samples from the Middle Hamanlei Limestone Formation were organic lean and had little source potential

Petroleum systems in the offshore Xihu Basin on the continental shelf of the East China Sea

Xihu Basin is one of the Cenozoic sedimentary basins within the continental shelf of the East China Sea, within which eight oil and gas fields and four hydrocarbon-bearing structures have been found. Our systematic analysis of potential petroleum systems in the basin has identified the Eocene Pinghu Formation as the most important source rock in the basin. The Eocene Pinghu Formation consists of mudstone and coal deposited in an embayment and tidal-flat environment and is characterized as containing type III kerogen. The Pinghu Formation is mature and, at the present time, is within the oil and wet-gas windows with determined vitrinite reflectance values in the range of 0.55–2.2% measured vitrinite reflectance (Rom). Modeling results suggest that the main stage of hydrocarbon expulsion occurred during the Miocene. The main reservoir consists of fine-grained sandstones of the Huagang and Pinghu formations deposited within shallow lacustrine and estuarine environments. The measured porosity from core samples of reservoir rock ranges from 10 to 35%, whereas permeability values range from 1 to 4000 md; both porosity and permeability decrease with depth. The mudstones of the upper Huagang and Longjing formations also occur as regional seals, which developed overpressure zones as determined by two-way sonic transit times. The overburden includes all the Oligocene, Miocene, Pliocene, and Quaternary strata. The hydrocarbon traps in the basin are mainly structural traps, including faulted blocks, faulted structural noses, and anticlines. Most traps were developed at the ends of the Eocene or Oligocene. Hydrocarbons produced from the Xihu Basin are predominantly natural gases with minor amounts of crude oil. The crude oil in the basin is characterized by a low density, low sulfur, low wax, low vanadium/nickel ratio, a low resin and asphaltene content, and a high proportion of saturated hydrocarbons. The natural gas in the basin is composed predominantly of methane, with an average C1/C1–5 ratio of 0.89 and a C1/C2–5 ratio of 8.6. Two petroleum systems have been identified in the basin: the known Pinghu-Huagang and the hypothetical Huagang-Huagang systems. The Pinghu-Huagang is the major petroleum system and most important for oil and natural gas exploration in the basin.

The effect of long-term low-temperature exposure on apatite fission track stability: A natural annealing experiment in the deep ocean

Since studies on deep-sea cores were carried out in the early 1990s it has been known that ambient temperature may have a marked affect on apatite fission track annealing. Due to sluggish annealing kinetics, this effect cannot be quantified by laboratory annealing experiments. The unknown amount of low-temperature annealing remains one of the main uncertainties for extracting thermal histories from fission track data, particularly for samples which experienced slow cooling in shallow crustal levels. To further elucidate these uncertainties, we studied volcanogenic sediments from five deep-sea drill cores, that were exposed to maximum temperatures between ∼10° and 70 °C over geological time scales of ∼15–120 Ma. Mean track lengths (MTL) and etch pit diameters (Dpar) of all samples were measured, and the chemical composition of each grain analysed for age and track length measurements was determined by electron microprobe analysis. Thermal histories of the sampled sites were independently reconstructed, based on vitrinite reflectance measurements and/or 1D numerical modelling. These reconstructions were used to test the most widely used annealing models for their ability to predict low-temperature annealing. Our results show that long-term exposure to temperatures below the temperature range of the nominal apatite fission track partial annealing zone results in track shortening ranging between 4 and 11%. Both chlorine content and Dpar values explain the downhole annealing patterns equally well. Low chlorine apatite from one drill core revealed a systematic relation between Si-content and Dpar value. The question whether Si-substitution in apatite has direct and systematic effects on annealing properties however, cannot be addressed by our data. For samples, which remained at temperatures <30 °C, and which are low in chlorine, the Laslett et al. [Laslett G., Green P., Duddy I. and Gleadow A. (1987) Thermal annealing of fission tracks in apatite. Chem. Geol. 65, 1–13] annealing model predicts MTL up to 0.6 μm longer than those actually measured, whereas for apatites with intermediate to high chlorine content, which experienced temperatures >30 °C, the predictions of the Laslett et al. (1987) model agree with the measured MTL data within error levels. With few exceptions, predictions by the Ketcham et al. [Ketcham R., Donelick R. and Carlson W. (1999) Variability of apatite fission-track annealing kinetics. III: Extrapolation to geological time scales. Am. Mineral. 84/9, 1235–1255] annealing model are consistent with the measured data for samples which remained at temperatures below ∼30 °C. For samples which experienced maximum temperatures between ∼30 and 70 °C, and which are rich in chlorine, the Ketcham et al. (1999) model overestimates track annealing.

Nearshore Mesozoic basins off Nordland, Norway: Structure, age and sedimentary environment

Seismic data acquisition along the Nordland coast (Norway) has resulted in the discovery of two downfaulted sedimentary basins of Mesozoic age in an area of Precambrian–Lower Palaeozoic metamorphic rocks. The Stabbfjorden Basin (informal name) west of Meløya has a sedimentary rock succession that is up to 800 m thick, while the Lyngværfjorden Basin (informal name) northeast of Træna is at least 350 m deep. Microfossil dating of ice-transported erratic blocks thought to be eroded from these basins and found on nearby skerries range in age from Barremian to Triassic. The majority of the samples are of Middle-Late Jurassic age. The sedimentary blocks comprise conglomerates, sandstones, siltstones and mudstones, and frequently contain shells and coal fragments. Lithofacies analyses show that they reflect shallow marine deposition, but it is possible that the oldest samples were deposited in a continental environment. The lithofacies reflect the well-known tectonic phases and sea-level changes that have been reported for the Middle Jurassic–Early Cretaceous in the Nordland offshore region. Vitrinite reflectance measurements show that organic material in the samples can be classified as immature, and the newly discovered basins have no hydrocarbon exploration potential.

Geologic framework of the Mississippian Barnett Shale, Barnett-Paleozoic total petroleum system, Bend arch–Fort Worth Basin, Texas

This article describes the primary geologic characteristics and criteria of the Barnett Shale and Barnett-Paleozoic total petroleum system (TPS) of the Fort Worth Basin used to define two geographic areas of the Barnett Shale for petroleum resource assessment. From these two areas, referred to as assessment units, the U.S. Geological Survey estimated a mean volume of about 26 tcf of undiscovered, technically recoverable hydrocarbon gas in the Barnett Shale. The Mississippian Barnett Shale is the primary source rock for oil and gas produced from Paleozoic reservoir rocks in the Bend arch–Fort Worth Basin area and is also one of the most significant gas-producing formations in Texas. Subsurface mapping from well logs and commercial databases and petroleum geochemistry demonstrate that the Barnett Shale is organic rich and thermally mature for hydrocarbon generation over most of the Bend arch–Fort Worth Basin area. In the northeastern and structurally deepest part of the Fort Worth Basin adjacent to the Muenster arch, the formation is more than 1000 ft (305 m) thick and interbedded with thick limestone units; westward, it thins rapidly over the Mississippian Chappel shelf to only a few tens of feet. The Barnett-Paleozoic TPS is identified where thermally mature Barnett Shale has generated large volumes of hydrocarbons and is (1) contained within the Barnett Shale unconventional continuous accumulation and (2) expelled and distributed among numerous conventional clastic- and carbonate-rock reservoirs of Paleozoic age. Vitrinite reflectance (Ro) measurements show little correlation with present-day burial depth. Contours of equal Ro values measured from Barnett Shale and typing of produced hydrocarbons indicate significant uplift and erosion. Furthermore, the thermal history of the formation was enhanced by hydrothermal events along the Ouachita thrust front and Mineral Wells–Newark East fault system. Stratigraphy and thermal maturity define two gas-producing assessment units for the Barnett Shale: (1) a greater Newark East fracture-barrier continuous Barnett Shale gas assessment unit, encompassing an area of optimal gas production where dense impermeable limestones enclose thick (300 ft; 91 m) Barnett Shale that is within the gas-generation window (Ro 1.1%); and (2) an extended continuous Barnett Shale gas assessment unit covering an area where the Barnett Shale is within the gas-generation window, but is less than 300 ft (91 m) thick, and either one or both of the overlying and underlying limestone barriers are absent.

Potential source rocks, organic geochemistry and thermal maturation in the southern depocenter (Kipourio–Grevena) of the Mesohellenic Basin, central Greece

Abstract The study area is the southern depocenter (depth > 4200 m) of the Mesohellenic Basin which extends between Kipourio and Grevena, central Greece. The Mesohellenic Basin is a Middle-Tertiary intramontane basin developed within the Hellenide orogen. Previous studies have focused on the depositional environments, configuration and hydrocarbon potential of the basin. In this paper we present additional geochemical and petrographic data from outcrop samples of the basin's southern depocenter, which is considered the most promising area, in terms of hydrocarbon prospectivity. A total number of thirty six samples were analysed: Rock-Eval pyrolysis, maceral analysis, vitrinite reflectance and thermal alteration index, bitumens extraction, liquid chromatography, and GC-MS. The samples were collected from deltaic deposits and submarine fan sediments of Late Eocene to Late Oligocene age. The TOC values of the analysed samples range between rich and very rich and the organic matter consists mainly of type III kerogen and the organic matter consider to be predominately gas prone. The thermal maturity assessed from Tmax and vitrinite reflectance shows an immature stage of the organic matter along with the presence of layers having reached the very early mature stage. Vitrinite reflectance measurements and maturity calculations (applying the Lopatin modeling), reveal that the lower part of the depocenter sediments falls within the ‘oil window’. The extractable organic matter (EOM) (mg bitumens/g TOC) indicate the existence of samples (from deltaic deposits) with high ratio of transformation (EOM) (> 100 mg bitumen/g TOC). The GC and GC-MS analyses of the biomarkers indicate mainly the occurrence of terrestrial organic matter reflecting oxidizing conditions and both immature and very early mature stages. The results of the Rock-Eval pyrolysis and the distribution of the isoprenoids support the assumption of the input of an organic matter mixture.

Diamondoid hydrocarbons as a molecular proxy for thermal maturity and oil cracking: Geochemical models from hydrous pyrolysis

A series of isothermal hydrous pyrolysis experiments was performed on immature sedimentary rocks and peats of different lithology and organic source input to explore the generation of diamondoids during the thermal maturation of sediments. Oil generation curves indicate that peak oil yields occur between 340 and 360 °C, followed by intense oil cracking in different samples. The biomarker maturity parameters appear to be insensitive to thermal maturation as most of the isomerization ratios of molecular biomarkers in the pyrolysates have reached their equilibrium values. Diamondoids are absent from immature peat extracts, but exist in immature sedimentary rocks in various amounts. This implies that they are not products of biosynthesis and that they may be generated during diagenesis, not just catagenesis and cracking. Most importantly, the concentrations of diamondoids are observed to increase with thermal stress, suggesting that they can be used as a molecular proxy for thermal maturity of source rocks and crude oils. Their abundance is most sensitive to thermal exposure above temperatures of 360–370 °C ( R 0 = 1.3–1.5%) for the studied samples, which corresponds to the onset of intense cracking of other less stable components. Below these temperatures, diamondoids increase gradually due to competing processes of generation and dilution. Calibrations were developed between their concentrations and measured vitrinite reflectance through hydrous pyrolysis maturation of different types of rocks and peats. The geochemical models obtained from these methods may provide an alterative approach for determining thermal maturity of source rocks and crude oils, particularly in mature to highly mature Paleozoic carbonates. In addition, the extent of oil cracking was quantified using the concentrations of diamondoids in hydrous pyrolysates of rocks and peats, verifying that these hydrocarbons are valuable indicators of oil cracking in nature.

PETROLEUM POTENTIAL, THERMAL MATURITY AND THE OIL WINDOW OF OIL SHALES AND COALS IN CENOZOIC RIFT BASINS, CENTRAL AND NORTHERN THAILAND

Oil shales and coals occur in Cenozoic rift basins in central and northern Thailand. Thermally immature outcrops of these rocks may constitute analogues for source rocks which have generated oil in several of these rift basins. A total of 56 oil shale and coal samples were collected from eight different basins and analysed in detail in this study. The samples were analysed for their content of total organic carbon (TOC) and elemental composition. Source rock quality was determined by Rock‐Eval pyrolysis. Reflected light microscopy was used to analyse the organic matter (maceral) composition of the rocks, and the thermal maturity was determined by vitrinite reflectance (VR) measurements. In addition to the 56 samples, VR measurements were carried out in three wells from two oil‐producing basins and VR gradients were constructed. Rock‐Eval screening data from one of the wells is also presented. The oil shales were deposited in freshwater (to brackish) lakes with a high preservation potential (TOC contents up to 44.18 wt%). They contain abundant lamalginite and principally algal‐derived fluorescing amorphous organic matter followed by liptodetrinite and telalginite (Botryococcus‐type). Huminite may be present in subordinate amounts. The coals are completely dominated by huminite and were formed in freshwater mires. VR values from 0.38 to 0.47%Ro show that the exposed coals are thermally immature. VR values from the associated oil shales are suppressed by 0.11 to 0.28%Ro. The oil shales have H/C ratios &gt;1.43, and Hydrogen Index (HI) values are generally &gt;400 mg HC/g TOC and may reach 704 mg HC/ gTOC. In general, the coals have H/C ratios between about 0.80 and 0.90, and the HI values vary considerably from approximately 50 to 300 mg HC/gTOC. The HImax of the coals, which represent the true source rock potential, range from ∼160 to 310 mg HC/g TOC indicating a potential for oil/gas and oil generation. The steep VR curves from the oil‐producing basins reflect high geothermal gradients of ∼62°C/km and ∼92°C/km. The depth to the top oil window for the oil shales at a VR of ∼0.70%Ro is determined to be between ∼1100 m and 1800 m depending on the geothermal gradient. The kerogen composition of the oil shales and the high geothermal gradients result in narrow oil windows, possibly spanning only ∼300 to 400 m in the warmest basins. The effective oil window of the coals is estimated to start from ∼0.82 to 0.98%Ro and burial depths of ∼1300 to 1400 m (∼92°C/km) and ∼2100 to 2300 m (∼62°C/km) are necessary for efficient oil expulsion to occur.