DETERMINATION OF THE HYDROCARBON PROSPECTIVITY OF SEDIMENTS BY HYDROGENATION

1984 ◽  
Vol 24 (1) ◽  
pp. 222 ◽  
Author(s):  
E. J. Evans ◽  
B. D. Batts
Keyword(s):  
Liquid Hydrocarbon ◽  
Land Plant ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Content ◽  
Hydrocarbon Maturation ◽  
Significant Difference ◽  
Recent Developments ◽  
Exploratory Wells

Recent developments in hydrogenation procedures allow the liquid hydrocarbon potential and the total liquid hydrocarbon content of source rocks to be determined directly. In essence, mild controlled hydrogenation. without the cleavage of C-C bonds, converts the recognized hydrocarbon precursors in immature source rocks, i.e. the largely aliphatic acids, alcohols, esters, etc., into the parent alkanes. These alkanes, which have a distinctive composition, are easily collected and determined in toto by routine analytical processes. Thus hydrocarbon potentials are immediately revealed.Since the bulk of Australian crudes are of land plant (humic) origin, initial investigations have been largely concentrated on vitrinites and inertinites separated from Australian coals. These studies have shown that:the formation, on hydrogenation, of alkanes with a distinctive composition is an excellent guide to sediment maturity and to hydrocarbon potential; hydrocarbon generation, although not hydrocarbon maturation, is complete when the reflectance of vitrinite in contributing sediments approximates 0.65 per cent; and no significant difference exists between the hydrocarbon potentials and the hydrocarbon content of associated inertinites and vitrinites when the reflectance of the latter is in the range 0.3 to 1.2 per cent. These findings provide a guide to basin potentials and an explanation for the unexpected prospectivity of inertinite-rich Australian sediments.Results of applying this procedure to sediment samples from exploratory wells in the Gippsland and Cooper Basins have generally followed trends seen with coal samples and confirmed the value of the method in determining hydrocarbon potentials.

Kinetic study of the hydrocarbon generation from marine carbonate source rocks characterization of products of gas and liquid hydrocarbon

2006 ◽  
Vol 51 (23) ◽  
pp. 2885-2891 ◽  
Author(s):  
Xinhua Geng ◽  
Ansong Geng ◽  
Yongqiang Xiong ◽  
Jinzhong Liu ◽  
Haizu Zhang ◽  
...  
Keyword(s):  
Kinetic Study ◽  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Marine Carbonate ◽  
Carbonate Source

scholarly journals New exploration strategy in igneous petroliferous basins – Enlightenment from simulation experiments

2018 ◽  
Vol 36 (4) ◽  
pp. 971-985
Author(s):  
Qingqiang Meng ◽  
Jiajun Jing ◽  
Jingzhou Li ◽  
Dongya Zhu ◽  
Ande Zou ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Liquid Hydrocarbon ◽  
Hydrogen Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Simulation Experiments ◽  
Gaseous Hydrocarbon ◽  
Oil And Gas Fields ◽  
Gaseous Hydrocarbons ◽  
Hydrocarbon Productivity

There are two kinds of relationships between magmatism and the generation of hydrocarbons from source rocks in petroliferous basins, namely: (1) simultaneous magmatism and hydrocarbon generation, and (2) magmatism that occurs after hydrocarbon generation. Although the influence of magmatism on hydrocarbon source rocks has been extensively studied, there has not been a systematic comparison between these two relationships and their influences on hydrocarbon generation. Here, we present an overview of the influence of magmatism on hydrocarbon generation based on the results of simulation experiments. These experiments indicate that the two relationships outlined above have different influences on the generation of hydrocarbons. Magmatism that occurred after hydrocarbon generation contributed deeply sourced hydrogen gas that improved liquid hydrocarbon productivity between the mature and overmature stages of maturation, increasing liquid hydrocarbon productivity to as much as 451.59% in the case of simulation temperatures of up to 450°C during modelling where no hydrogen gas was added. This relationship also increased the gaseous hydrocarbon generation ratio at temperatures up to 450°C, owing to the cracking of initially generated liquid hydrocarbons and the cracking of kerogen. Our simulation experiments suggest that gaseous hydrocarbons dominate total hydrocarbon generation ratios for overmature source rocks, resulting in a change in petroleum accumulation processes. This in turn suggests that different exploration strategies are warranted for the different relationships outlined above. For example, simultaneous magmatism and hydrocarbon generation in an area means that exploration should focus on targets likely to host large oilfields, whereas in areas with magmatism that post-dates hydrocarbon generation the exploration should focus on both oil and gas fields. In addition, exploration strategies in igneous petroliferous basins should focus on identifying high-quality reservoirs as well as determining the relationship between magmatism and initial hydrocarbon generation.

scholarly journals Thermal Maturation Regime Revisited in the Dongying Depression, Bohai Bay Basin, East China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-17
Author(s):  
Haiping Huang ◽  
Hong Zhang ◽  
Zheng Li ◽  
Mei Liu
Keyword(s):  
Organic Geochemistry ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
East China ◽  
Burial Depth ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Bohai Bay Basin ◽  
Dongying Depression ◽  
Hydrocarbon Maturation

To the accurate reconstruction of the hydrocarbon generation history in the Dongying Depression, Bohai Bay Basin, East China, core samples of the Eocene Shahejie Formation from 3 shale oil boreholes were analyzed using organic petrology and organic geochemistry methods. The shales are enriched in organic matter with good to excellent hydrocarbon generation potential. The maturity indicated by measured vitrinite reflectance (%Ro) falls in the range of 0.5–0.9% and increases with burial depth in each well. Changes in biomarker and aromatic hydrocarbon isomer distributions and biomarker concentrations are also unequivocally correlated with the thermal maturity of the source rocks. Maturity/depth relationships for hopanes, steranes, and aromatic hydrocarbons, constructed from core data indicate different well locations, have different thermal regimes. A systematic variability of maturity with geographical position along the depression has been illustrated, which is a dependence on the distance to the Tanlu Fault. Higher thermal gradient at the southern side of the Dongying Depression results in the same maturity level at shallower depth compared to the northern side. The significant regional thermal regime change from south to north in the Dongying Depression may exert an important impact on the timing of hydrocarbon maturation and expulsion at different locations. Different exploration strategies should be employed accordingly.

scholarly journals Oil generation from coal source rocks: the influence of depositional conditions and stratigraphic age

2005 ◽  
Vol 7 ◽  
pp. 9-12 ◽  
Author(s):  
Henrik I. Petersen
Keyword(s):  
North Sea ◽  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Oil Generation ◽  
Generation Capacity ◽  
The Subject ◽  
Coal Composition ◽  
Gippsland Basin ◽  
Australasian Region

Although it was for many years believed that coals could not act as source rocks for commercial oil accumulations, it is today generally accepted that coals can indeed generate and expel commercial quantities of oil. While hydrocarbon generation from coals is less well understood than for marine and lacustrine source rocks, liquid hydrocarbon generation from coals and coaly source rocks is now known from many parts of the world, especially in the Australasian region (MacGregor 1994; Todd et al. 1997). Most of the known large oil accumulations derived from coaly source rocks have been generated from Cenozoic coals, such as in the Gippsland Basin (Australia), the Taranaki Basin (New Zealand), and the Kutei Basin (Indonesia). Permian and Jurassic coal-sourced oils are known from, respectively, the Cooper Basin (Australia) and the Danish North Sea, but in general only minor quantities of oil appear to be related to coals of Permian and Jurassic age. In contrast, Carboniferous coals are only associated with gas, as demonstrated for example by the large gas deposits in the southern North Sea and The Netherlands. Overall, the oil generation capacity of coals seems to increase from the Carboniferous to the Cenozoic. This suggests a relationship to the evolution of more complex higher land plants through time, such that the highly diversified Cenozoic plant communities in particular have the potential to produce oil-prone coals. In addition to this overall vegetational factor, the depositional conditions of the precursor mires influenced the generation potential. The various aspects of oil generation from coals have been the focus of research at the Geological Survey of Denmark and Greenland (GEUS) for several years, and recently a worldwide database consisting of more than 500 coals has been the subject of a detailed study that aims to describe the oil window and the generation potential of coals as a function of coal composition and age.

TECTONOSTRATIGRAPHY AND POTENTIAL SOURCE ROCKS OF THE BASS BASIN

2005 ◽  
Vol 45 (1) ◽  
pp. 601 ◽  
Author(s):  
J.E. Blevin ◽  
K.R. Trigg ◽  
A.D. Partridge ◽  
C.J. Boreham ◽  
S.C. Lang
Keyword(s):  
Seismic Data ◽  
Middle Eocene ◽  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
Rift System ◽  
Complex Nature ◽  
Hydrocarbon Generation ◽  
Crustal Extension ◽  
Principal Source ◽  
Seismic Sequence Stratigraphy

A study of the Bass Basin using a basin-wide integration of seismic data, well logs, biostratigraphy and seismic/sequence stratigraphy has resulted in the identification of six basin phases and related megasequences/ supersequences. These sequences correlate to three periods of extension and three subsidence phases. The complex nature of facies relationships across the basin is attributed to the mostly terrestrial setting of the basin until the Middle Eocene, multiple phases of extension, strong compartmentalisation of the basin due to underlying basement fabric, and differential subsidence during extension and early subsidence phases. The Bass Basin formed through upper crustal extension associated with three main regional events:rifting in the Southern Margin Rift System;rifting associated with the formation of the Tasman Basin; and,prolonged separation, fragmentation and clearance between the Australian and Antarctic plates along the western margin of Tasmania.The final stage of extension was the result of far-field stresses that were likely to be oblique in orientation. The late Early Eocene to Middle Eocene was a time of rifttransition and early subsidence as the effects of intra-plate stresses progressively waned from east to west. Most of the coaly source rocks now typed to liquid hydrocarbon generation were deposited during this rift-transition phase. Biostratigraphic studies have identified three major lacustrine episodes during the Late Cretaceous to Middle Eocene. The lacustrine shales are likely to be more important as seal facies, while coals deposited fringing the lakes are the principal source rocks in the basin.

GEOLOGY, SOURCE ROCKS AND HYDROCARBON GENERATION IN THE CLARENCE-MORETON BASIN

1982 ◽  
Vol 22 (1) ◽  
pp. 5
Author(s):  
A. R. Martin ◽  
J. D. Saxby
Keyword(s):  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Tectonic Events ◽  
History Of ◽  
Rock Eval ◽  
Coal Measures ◽  
Migration Pathways

The geology and exploration history of the Triassic-Cretaceous Clarence-Moreton Basin are reviewed. Consideration of new geochemical data ('Rock-Eval', vitrinite reflectance, gas chromatography of extracts, organic carbon and elemental analysis of coals and kerogens) gives further insights into the hydrocarbon potential of the basin. Although organic-rich rocks are relatively abundant, most source rocks that have achieved the levels of maturation necessary for hydrocarbon generation are gas-prone. The exinite-rich oil-prone Walloon Coal Measures are in most parts relatively immature. Some restraints on migration pathways are evident and igneous and tectonic events may have disturbed potentially well-sealed traps. Further exploration is warranted, even though the basin appears gas-prone and the overall prospects for hydrocarbons are only fair. The most promising areas seem to be west of Toowoomba for oil and the Clarence Syncline for gas.

scholarly journals Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine)

2012 ◽  
Vol 63 (4) ◽  
pp. 319-333 ◽  
Author(s):  
Paweł Kosakowski ◽  
Dariusz Więcław ◽  
Adam Kowalski ◽  
Yuriy Koltun
Keyword(s):  
Organic Matter ◽  
Middle Jurassic ◽  
Sedimentary Cover ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Source Rock ◽  
Core Samples ◽  
Se Poland ◽  
Geochemical Parameters

Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine) The Jurassic/Cretaceous stratigraphic complex forming a part of the sedimentary cover of both the eastern Małopolska Block and the adjacent Łysogóry-Radom Block in the Polish part as well as the Rava Rus'ka and the Kokhanivka Zones in the Ukrainian part of the basement of the Carpathian Foredeep were studied with geochemical methods in order to evaluate the possibility of hydrocarbon generation. In the Polish part of the study area, the Mesozoic strata were characterized on the basis of the analytical results of 121 core samples derived from 11 wells. The samples originated mostly from the Middle Jurassic and partly from the Lower/Upper Cretaceous strata. In the Ukrainian part of the study area the Mesozoic sequence was characterized by 348 core samples collected from 26 wells. The obtained geochemical results indicate that in both the south-eastern part of Poland and the western part of Ukraine the studied Jurassic/Cretaceous sedimentary complex reveals generally low hydrocarbon source-rock potential. The most favourable geochemical parameters: TOC up to 26 wt. % and genetic potential up to 39 mg/g of rock, were found in the Middle Jurassic strata. However, these high values are contradicted by the low hydrocarbon index (HI), usually below 100 mg HC/g TOC. Organic matter from the Middle Jurassic strata is of mixed type, dominated by gas-prone, Type III kerogen. In the Polish part of the study area, organic matter dispersed in these strata is generally immature (Tmax below 435 °C) whereas in the Ukrainian part maturity is sufficient for hydrocarbon generation.

scholarly journals Petrology and hydrocarbon significance of the coaly source rocks from the Pinghu Formation in the Xihu Sag, East China Sea Shelf Basin

2020 ◽  
Vol 38 (5) ◽  
pp. 1295-1319
Author(s):  
Jinshui Liu ◽  
Shilong Kang ◽  
Wenchao Shen ◽  
Lanzhi Qin ◽  
Qianyu Zhou ◽  
...  
Keyword(s):  
East China Sea ◽  
Oil And Gas ◽  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
East China ◽  
Lower Amount ◽  
Hydrocarbon Generation ◽  
Total Hydrocarbon ◽  
China Sea ◽  
East China Sea Shelf

The Xihu Sag in the East China Sea Shelf Basin contains abundant oil and gas reserves and is a focus for hydrocarbon exploration and development. Source rocks are mainly coals and coal-measures mudstones in the Paleogene Pinghu and Huagang formations. Samples from the Pinghu Formation in the Xihu Sag were collected for petrology, total organic carbon, and Rock-Eval analysis for the purpose of investigating macerals component and their contributions to hydrocarbon generation potential. The coaly source rocks from the Pinghu Formation are dominated by vitrinite (average 86.18%) but have an obviously elevated content of liptinite (average 12.59%) and a much lower amount of inertinite (average 1.23%). Liptinite of the samples is mainly composed of resinite, with a small amount of cutinite, sporinite and alginate in descending order. TOC values are 37.55%–65.58% (average 49.16%). Effective HI values are 167–281 mg HC/g TOC (average 223.5 mg HC/g TOC), suggesting the organic matter is type II kerogen. Relatively high HI values and macerals components suggest that the coaly source rocks can generate both oil and gas. Although the liptinite in the coaly source rocks has a content lower than vitrinite values, it makes a significant contribution to both total hydrocarbon and liquid hydrocarbon generation. The contributions of vitrinite, liptinite and inertinite to the total hydrocarbon generation approximately are 63.21%, 36.46% and 0.33%, respectively. The contributions of vitrinite and liptinite to the liquid hydrocarbon generation are approximately 40.95% and 59.05%, respectively. These results demonstrate that the coaly source rocks are dominated by vitrinite macerals with a relatively higher content of liptinite macerals, especially resinite, and these source rocks are more prone to both total hydrocarbon and liquid hydrocarbon generation. Paleogene coaly source rocks from other parts of the world should be considered for their oil-prone nature.

GEOCHEMICAL TOOLS FOR EVALUATING PETROLEUM GENERATION IN MIDDLE PROTEROZOIC SEDIMENTS OF THE McARTHUR BASIN, NORTHERN TERRITORY, AUSTRALIA

1994 ◽  
Vol 34 (1) ◽  
pp. 692 ◽  
Author(s):  
Roger E. Summons ◽  
Dennis Taylor ◽  
Christopher J. Boreham
Keyword(s):  
Vitrinite Reflectance ◽  
Land Plant ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Strongly Correlated ◽  
Petroleum Potential ◽  
Petroleum Generation ◽  
Early Palaeozoic ◽  
Geochemical Analyses ◽  
Rock Eval

Maturation parameters based on aromatic hydrocarbons, and particularly the methyl-phenanthrene index (MPI-1), are powerful indicators which can be used to define the oil window in Proterozoic and Early Palaeozoic petroleum source rocks and to compare maturities and detect migration in very old oils . The conventional vitrinite reflectance yardstick for maturity is not readily translated to these ancient sediments because they predate the evolution of the land plant precursors to vitrinite. While whole-rock geochemical tools such as Rock-Eval and TOC are useful for evaluation of petroleum potential, they can be imprecise when applied to maturity assessments.In this study, we carried out a range of detailed geochemical analyses on McArthur Basin boreholes penetrating the Roper Group source rocks. We determined the depth profiles for hydrocarbon generation based on Rock-Eval analysis of whole-rock, solvent-extracted rock, kerogen elemental H/C ratio and pyrolysis GC. Although we found that Hydrogen Index (HI) and the Tmax parameter were strongly correlated with other maturation indicators, they were not sufficiently sensitive nor were they universally applicable. Maturation measurements based on saturated biomarkers were not useful either because of the low abundance of these compounds in most Roper Group bitumens and oils.

Sign in / Sign up

Export Citation Format

Share Document