Source Rocks in Vienna Basin and Their Importance for Hydrocarbon Exploration Along Northern Edge of the Alps: ABSTRACT

AAPG Bulletin ◽  
1984 ◽  
Vol 68 ◽  
Author(s):  
H. W. Ladwein
Keyword(s):  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Vienna Basin ◽  
Northern Edge ◽  
The Alps

Oil to Source Rock Correlation Using Biomarker Data Through Pattern Matching and Fingerprinting Analysis in “Kitkat” Field, Jabung Block, South Sumatra Basin

2020 ◽  
Author(s):  
S., R. Muthasyabiha
Keyword(s):  
Pattern Matching ◽  
Source Rock ◽  
Vitrinite Reflectance ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Maturity Level ◽  
Fingerprinting Analysis ◽  
Kerogen Type ◽  
Oil Characteristics ◽  
Biomarker Data

Geochemical analysis is necessary to enable the optimization of hydrocarbon exploration. In this research, it is used to determine the oil characteristics and the type of source rock candidates that produces hydrocarbon in the “KITKAT” Field and also to understand the quality, quantity and maturity of proven source rocks. The evaluation of source rock was obtained from Rock-Eval Pyrolysis (REP) to determine the hydrocarbon type and analysis of the value of Total Organic Carbon (TOC) was performed to know the quantity of its organic content. Analysis of Tmax value and Vitrinite Reflectance (Ro) was also performed to know the maturity level of the source rock samples. Then the oil characteristics such as the depositional environment of source rock candidate and where the oil sample develops were obtained from pattern matching and fingerprinting analysis of Biomarker data GC/GCMS. Moreover, these data are used to know the correlation of oil to source rock. The result of source rock evaluation shows that the Talangakar Formation (TAF) has all these parameters as a source rock. Organic material from Upper Talangakar Formation (UTAF) comes from kerogen type II/III that is capable of producing oil and gas (Espitalie, 1985) and Lower Talangakar Formation (LTAF) comes from kerogen type III that is capable of producing gas. All intervals of TAF have a quantity value from very good–excellent considerable from the amount of TOC > 1% (Peters and Cassa, 1994). Source rock maturity level (Ro > 0.6) in UTAF is mature–late mature and LTAF is late mature–over mature (Peters and Cassa, 1994). Source rock from UTAF has deposited in the transition environment, and source rock from LTAF has deposited in the terrestrial environment. The correlation of oil to source rock shows that oil sample is positively correlated with the UTAF.

scholarly journals Middle and late Badenian palaeoenvironments in the northern Vienna Basin and their potential link to the Badenian Salinity Crisis

2018 ◽  
Vol 69 (2) ◽  
pp. 149-168 ◽  
Author(s):  
Mathias Harzhauser ◽  
Patrick Grunert ◽  
Oleg Mandic ◽  
Petra Lukeneder ◽  
Ángela García Gallardo ◽  
...  
Keyword(s):  
Fish Assemblages ◽  
Depositional Environments ◽  
Hydrocarbon Exploration ◽  
Vienna Basin ◽  
Seismic Surveys ◽  
Marine Mollusc ◽  
Potential Link ◽  
Glass Sponges ◽  
Sudden Appearance ◽  
Climate Transition

AbstractHydrocarbon exploration in the Bernhardsthal and Bernhardsthal-Sued oil fields documents an up to 2000 m thick succession of middle and upper Badenian deposits in this part of the northern Vienna Basin (Austria). Based on palaeontological analyses of core-samples, well-log data and seismic surveys we propose an integrated stratigraphy and describe the depositional environments. As the middle/late Badenian boundary is correlated with the Langhian/Serravallian boundary, the cores capture the crucial phase of the Middle Miocene Climate Transition. The middle Badenian starts with a major transgression leading to outer neritic to upper bathyal conditions in the northern Vienna Basin, indicated byBathysiphon-assemblages and glass-sponges. A strong palaeo-relief and rapid synsedimentary subsidence accentuated sedimentation during this phase. The middle/late Badenian boundary coincides with a major drop of relative sea level by about 200 m, resulting in a rapid shift from deeper marine depositional environments to coastal and freshwater swamps. In coeval marine settings, a more than 100 m thick unit of anhydrite-bearing clay formed. This is the first evidence of evaporite precipitation during the Badenian Salinity Crisis in the Vienna Basin. Shallow lagoonal environments with diverse and fully marine mollusc and fish assemblages were established during the subsequent late Badenian re-flooding. In composition, the mollusc fauna differs considerably from older ones and is characterized by the sudden appearance of species with eastern Paratethyan affinities.

scholarly journals Application of the Fractal Method to the Characterization of Organic Heterogeneities in Shales and Exploration Evaluation of Shale Oil

2019 ◽  
Vol 7 (4) ◽  
pp. 88 ◽  
Author(s):  
Bo Liu ◽  
Liangwen Yao ◽  
Xiaofei Fu ◽  
Bo He ◽  
Longhui Bai
Keyword(s):  
Organic Matter ◽  
Vertical Distribution ◽  
Power Law ◽  
Hurst Exponent ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Shale Oil ◽  
Box Counting Dimension ◽  
The Vertical Distribution

The first member of the Qingshankou Formation, in the Gulong Sag in the northern part of the Songliao Basin, has become an important target for unconventional hydrocarbon exploration. The organic-rich shale within this formation not only provides favorable hydrocarbon source rocks for conventional reservoirs, but also has excellent potential for shale oil exploration due to its thickness, abundant organic matter, the overall mature oil generation state, high hydrocarbon retention, and commonly existing overpressure. Geochemical analyses of the total organic carbon content (TOC) and rock pyrolysis evaluation (Rock-Eval) have allowed for the quantitative evaluation of the organic matter in the shale. However, the organic matter exhibits a highly heterogeneous spatial distribution and its magnitude varies even at the millimeter scale. In addition, quantification of the TOC distribution is significant to the evaluation of shale reservoirs and the estimation of shale oil resources. In this study, well log data was calibrated using the measured TOC of core samples collected from 11 boreholes in the study area; the continuous TOC distribution within the target zone was obtained using the △logR method; the organic heterogeneity of the shale was characterized using multiple fractal models, including the box-counting dimension (Bd), the power law, and the Hurst exponent models. According to the fractal dimension (D) calculation, the vertical distribution of the TOC was extremely homogeneous. The power law calculation indicates that the vertical distribution of the TOC in the first member of the Qingshankou Formation is multi-fractal and highly heterogeneous. The Hurst exponent varies between 0.23 and 0.49. The lower values indicate higher continuity and enrichment of organic matter, while the higher values suggest a more heterogeneous organic matter distribution. Using the average TOC, coefficient of variation (CV), Bd, D, inflection point, and the Hurst exponent as independent variables, the interpolation prediction method was used to evaluate the exploration potential of the study area. The results indicate that the areas containing boreholes B, C, D, F, and I in the western part of the Gulong Sag are the most promising potential exploration areas. In conclusion, the findings of this study are of significant value in predicting favorable exploration zones for unconventional reservoirs.

THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN

1995 ◽  
Vol 35 (1) ◽  
pp. 405 ◽  
Author(s):  
C.W. Luxton ◽  
S. T. Horan ◽  
D.L. Pickavance ◽  
M.S. Durham.
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Production Test ◽  
Water Contact ◽  
Excellent Quality ◽  
Fault Block ◽  
Well Location ◽  
Gas Fields

In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.

EXPLORATION AND EXPLOITATION OF A MATURE BASIN SUCCESSFUL APPLICATION OF A PROCESS-DRIVEN MULTI-DISCIPLINARYTEAM APPROACH

2000 ◽  
Vol 40 (1) ◽  
pp. 562
Author(s):  
W. Ringhofer ◽  
H. Sperl
Keyword(s):  
New Technology ◽  
Hydrocarbon Exploration ◽  
Vienna Basin ◽  
Sequence Stratigraphic ◽  
High Pressure High Temperature ◽  
Drilling Technology ◽  
Integration Of Disciplines ◽  
Well Data ◽  
Clastic Reservoirs ◽  
Overthrust Belt

From the early 1940s until the mid-1980s, hydrocarbon exploration within Austria was focussed upon Tertiary clastic reservoirs within the Vienna Basin. From 1980 to the early 1990s, an increasing number of exploration wells were drilled for carbonate reservoirs within deep thrust anticlines in the Alpine overthrust belt. These were typically high pressure-high temperature wells, and as a result, technically challenging and expensive.In the early 1990s, after little success within the Alpine overthrust belt, the focus of Austrian exploration was switched back to the 'maturely' explored Vienna Basin. During this period, the integration of historical well data, reprocessed 2D seismic and newly acquired 3D seismic data, evaluated within a sequence stratigraphic framework, has facilitated the accurate placement of multi-target wells. Together with the application of new drilling technology, the result has been a dramatic increase in new field discoveries. The reserves size of exploration and appraisal targets, in accordance with the maturity of the basin, have been relatively small, but, as a result of well-developed infrastructure and low drilling costs, highly profitable.The drive for increased drilling success and cost reduction and the application of 'new' technology has demanded an even closer integration of disciplines including exploration, reservoir engineering, drilling and production engineering. This integration in turn has necessitated process driven management. Multi- disciplinary teams, working with key contractors in an incentivised environment, achieved risk reduction, increased exploration success and budget reductions. As a result successful exploration has revived the mature Vienna Basin.

Deep Gas Theory as an Exploratory Tool

1987 ◽  
Vol 5 (4) ◽  
pp. 255-264
Author(s):  
David J. Bardin
Keyword(s):  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Additional Tool ◽  
Deep Earth

Deep earth gas theory, as propounded by Professor Thomas Gold or adapted from his ideas, can supplement other models considered by explorationists, even if the theory is accepted only in part or viewed skeptically and selectively. We trace the background of the theory and outline its elaboration, respecting source rocks, migration and indicators of hydrocarbons, which bear on different aspects of exploration. We then show how implications of the theory, or portions of it, can be applied as an additional tool for hydrocarbon exploration, as well as for addressing the hydrocarbon potentials of unexplored or little-explored areas.

ORGANIC GEOCHEMICAL EVALUATION OF POTENTIAL CENOZOIC SOURCE ROCKS IN THE MOGHAN BASIN, NW IRAN: IMPLICATIONS FOR HYDROCARBON EXPLORATION

2018 ◽  
Vol 41 (3) ◽  
pp. 393-410 ◽  
Author(s):  
M. Mirshahani ◽  
H. Bahrami ◽  
M. Rashidi ◽  
E. Tarhandeh ◽  
B. Khani
Keyword(s):  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Nw Iran ◽  
Geochemical Evaluation

Tectonostratigraphic development and hydrocarbon reservoir quality on a convergent margin: East Coast, North Island, New Zealand

2009 ◽  
Vol 49 (2) ◽  
pp. 600
Author(s):  
Brad Field ◽  
Jan Baur ◽  
Kyle Bland ◽  
Greg Browne ◽  
Angela Griffin ◽  
...  
Keyword(s):  
Late Cretaceous ◽  
East Coast ◽  
Fractured Reservoirs ◽  
Hydrocarbon Exploration ◽  
Passive Margin ◽  
Source Rocks ◽  
Reservoir Quality ◽  
High Porosity ◽  
Hydrocarbon Reservoir ◽  
Reservoir Potential

Hydrocarbon exploration on the East Coast of the North Island has not yet yielded significant commercial reserves, even though the elements of a working petroleum system are all present (Field et al, 1997). Exploration has focussed on the shallow, Neogene part of the succession, built up during plate margin convergence over the last ∼24 million years. Convergent margins are generally characterised by low-total organic carbon (TOC) source rocks and poor clastic reservoir quality due to poor sorting and labile grains. However, the obliquely-convergent Hikurangi subduction margin of the East Coast has high TOC source rocks that pre-date the subduction phase, and its reservoir potential, though variable, has several aspects in its favour, namely: deep-water rocks of high porosity and permeability; preservation of pore space by overpressure; the presence of fractured reservoirs and hybrid reservoirs, where low clastic permeability is enhanced by fractures. The East Coast North Island is a Neogene oblique subduction margin, with Neogene shelf and slope basins that developed on Late Cretaceous-Paleogene passive margin marine successions. The main hydrocarbon source rocks are Late Cretaceous and Paleocene and the main reservoir potential is in the Neogene (Field et al, 2005). Miocene mudstones with good seal potential are common, as is significant over-pressuring. Neogene deformation controlled basin development and accommodation space and strongly-influenced lateral facies development and fractured reservoirs. Early to Middle Miocene thrusting was followed by later Neogene extension (e.g. Barnes et al 2002), with a return to thrusting in the Pliocene. Local wells have flow-tested gas shows.

DEEP-WATER OTWAY BASIN: A NEW ASSESSMENT OF THE TECTONICS AND HYDROCARBON PROSPECTIVITY

2000 ◽  
Vol 40 (1) ◽  
pp. 66 ◽  
Author(s):  
A.M.G. Moore ◽  
H.M.J. Stagg ◽  
M.S. Norvick
Keyword(s):  
Continental Shelf ◽  
Continental Slope ◽  
Deep Water ◽  
South Australia ◽  
Petroleum System ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Rift System ◽  
Crust And Upper Mantle ◽  
Data Set

The northwest-trending Otway Basin in southeast Australia formed during the separation of Australia and Antarctica between the latest Jurassic and the Early Cainozoic. A new, deep-seismic data set shows that the basin comprises two temporally and spatially overlapping rift components:the mainly Late Jurassic to mid-Cretaceous, east-west trending, inner Otway Basin—comprising the onshore basin and most of the continental shelf basin; andthe northwest–southeast to north–south trending depocentres beneath the outer shelf and continental slope, extending from eastern South Australia to the west coast of Tasmania, and a relatively minor and ill-defined sub-basin underlying the continental rise in water depths greater than about 4,500 m. This rift system was most active from the mid-Cretaceous to Palaeogene, and was strongly affected by sinistral strike-slip motion as Australia and Antarctica separated.The continental slope elements contain the bulk of the sediment volume in the basin. From northwest to southeast, these elements comprise the Beachport and Morum Sub-basins, the north-south trending Discovery Bay High, and the Nelson Sub-basin which appears to be structurally and stratigraphically continuous with the Sorell Basin off west Tasmania.The reflection character of the crust and upper mantle varies widely across the basin, and there is a strong correlation between that character and the basin configuration. It appears that accommodation space beneath the slope basin was created largely by extension and removal of most of the laminated deep continental crust.There is encouragement for hydrocarbon exploration in the deep-water basin. Firstly, there are indications of diagenesis related to fluid flow in and above the strongly faulted Cretaceous section in the Morum Sub-basin. As an Early Cretaceous petroleum system is already proven beneath the continental shelf, this suggests that the same system is also active in deep-water. Secondly, existing sample data suggest that a second, Late Cretaceous petroleum system could be active where any source rocks are sufficiently deeply buried; this condition would probably be met in the Nelson Sub-basin.

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