scholarly journals Organic content and maturation effects on elastic properties of source rock shales in the Central North Sea

2019 ◽  
Vol 7 (2) ◽  
pp. T477-T497 ◽  
Author(s):  
Jørgen André Hansen ◽  
Nazmul Haque Mondol ◽  
Manzar Fawad
Keyword(s):  
Elastic Properties ◽  
Source Rock ◽  
North Sea ◽  
Empirical Relation ◽  
Organic Content ◽  
Rock Properties ◽  
Geochemical Data ◽  
Well Log ◽  
Seismic Properties ◽  
Central North Sea

We have investigated the effects of organic content and maturation on the elastic properties of source rock shales, mainly through integration of a well-log database from the Central North Sea and associated geochemical data. Our aim is to improve the understanding of how seismic properties change in source rock shales due to geologic variations and how these might manifest on seismic data in deeper, undrilled parts of basins in the area. The Tau and Draupne Formations (Kimmeridge shale equivalents) in immature to early mature stages exhibit variation mainly related to compaction and total organic carbon (TOC) content. We assess the link between depth, acoustic impedance (AI), and TOC in this setting, and we express it as an empirical relation for TOC prediction. In addition, where S-wave information is available, we combine two seismic properties and infer rock-physics trends for semiquantitative prediction of TOC from [Formula: see text] and AI. Furthermore, data from one reference well penetrating mature source rock in the southern Viking Graben indicate that a notable hydrocarbon effect can be observed as an addition to the inherently low kerogen-related velocity and density. Published Kimmeridge shale ultrasonic measurements from 3.85 to 4.02 km depth closely coincide with well-log measurements in the mature shale, indicating that upscaled log data are reasonably capturing variations in the actual rock properties. Amplitude variation with offset inversion attributes should in theory be interpreted successively in terms of compaction, TOC, and maturation with associated generation of hydrocarbons. Our compaction-consistent decomposition of these effects can be of aid in such interpretations.

scholarly journals Geophysical imaging of porosity variations in the Danish North Sea chalk

2008 ◽  
Vol 15 ◽  
pp. 17-20 ◽  
Author(s):  
Tanni Abramovitz
Keyword(s):  
North Sea ◽  
Seismic Reflection ◽  
Seismic Inversion ◽  
Rock Properties ◽  
Well Log ◽  
Reservoir Properties ◽  
Seismic Reflection Data ◽  
Log Data ◽  
The North ◽  
The North Sea

More than 80% of the present-day oil and gas production in the Danish part of the North Sea is extracted from fields with chalk reservoirs of late Cretaceous (Maastrichtian) and early Paleocene (Danian) ages (Fig. 1). Seismic reflection and in- version data play a fundamental role in mapping and characterisation of intra-chalk structures and reservoir properties of the Chalk Group in the North Sea. The aim of seismic inversion is to transform seismic reflection data into quantitative rock properties such as acoustic impedance (AI) that provides information on reservoir properties enabling identification of porosity anomalies that may constitute potential reservoir compartments. Petrophysical analyses of well log data have shown a relationship between AI and porosity. Hence, AI variations can be transformed into porosity variations and used to support detailed interpretations of porous chalk units of possible reservoir quality. This paper presents an example of how the chalk team at the Geological Survey of Denmark and Greenland (GEUS) integrates geological, geophysical and petrophysical information, such as core data, well log data, seismic 3-D reflection and AI data, when assessing the hydrocarbon prospectivity of chalk fields.

AN EARLY CRETACEOUS SOURCE ROCK IN THE KENDREW TERRACE, DAMPIER SUB-BASIN?

1996 ◽  
Vol 36 (1) ◽  
pp. 477 ◽  
Author(s):  
S. Ryan-Grigor ◽  
C. M. Griffiths
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Early Cretaceous ◽  
Late Jurassic ◽  
Large Scale ◽  
Free Water ◽  
Organic Content ◽  
Source Rocks ◽  
The North ◽  
Northern North Sea

The Early to Middle Cretaceous is characterised worldwide by widespread distribution of dark shales with high gamma ray readings and high organic contents defined as dark coloured mudrocks having the sedimentary, palaeoecological and geochemical characteristics associated with deposition under oxygen-deficient or oxygen-free bottom waters. Factors that contributed to the formation of the Early to Middle Cretaceous 'hot shales' are: rising sea-level, a warm equable climate which promoted water stratification, and large scale palaeogeographic features that restrict free water mixing. In the northern North Sea, the main source rock is the Late Jurassic to Early Cretaceous Kimmeridge Clay/Draupne Formation 'hot shale' which occurs within the Viking Graben, a large fault-bounded graben, in a marine environment with restricted bottom circulation and often anaerobic conditions. Opening of the basin during a major trans-gressive event resulted in flushing, and deposition of normal open marine shales above the 'hot shales'. The Late Callovian to Berriasian sediments in the Dampier Sub-basin are considered to have been deposited in restricted marine conditions below a stratified water column, in a deep narrow bay. Late Jurassic to Early Cretaceous marine sequences that have been cored on the North West Shelf are generally of moderate quality, compared to the high quality source rocks of the northern North Sea, but it should be noted that the cores are from wells on structural highs. The 'hot shales' are not very organic-rich in the northern Dampier Sub-basin and are not yet within the oil window, however seismic data show a possible reduction in velocity to the southwest in the Kendrew Terrace, suggesting that further south in the basin the shales may be within the oil window and may also be richer in organic content. In this case, they may be productive source rocks, analogous to the main source rock of the North Sea.

Reservoir quality and rock properties modeling – Triassic and Jurassic sandstones, greater Shearwater area, UK Central North Sea

2015 ◽  
Vol 65 ◽  
pp. 1-21 ◽  
Author(s):  
Thomas R. Taylor ◽  
Mark G. Kittridge ◽  
Peter Winefield ◽  
L. Taras Bryndzia ◽  
Linda M. Bonnell
Keyword(s):  
North Sea ◽  
Rock Properties ◽  
Reservoir Quality ◽  
Central North Sea

Visualization of vertical hydrocarbon migration in seismic data: Case studies from the Dutch North Sea

2015 ◽  
Vol 3 (3) ◽  
pp. SX21-SX27 ◽  
Author(s):  
David L. Connolly
Keyword(s):  
Neural Network ◽  
North Sea ◽  
Seismic Data ◽  
3D Visualization ◽  
Three Dimensions ◽  
Rock Properties ◽  
Geochemical Data ◽  
Lateral Migration ◽  
Hydrocarbon Migration ◽  
Migration Pathways

Previous 3D visualization studies in seismic data have largely been focused on visualizing reservoir geometry. However, there has been less effort to visualize the vertical hydrocarbon migration pathways, which may provide charge to these reservoirs. Vertical hydrocarbon migration was recognized in normally processed seismic data as vertically aligned zones of chaotic low-amplitude seismic response called gas chimneys, blowout pipes, gas clouds, mud volcanoes, or hydrocarbon-related diagenetic zones based on their morphology, rock properties, and flow mechanism. Because of their diffuse character, they were often difficult to visualize in three dimensions. Thus, a method has been developed to detect these features using a supervised neural network. The result is a “chimney” probability volume. However, not all chimneys detected by this method will represent true hydrocarbon migration. Therefore, the neural network results must be validated by a set of criteria that include (1) pockmarked morphology, (2) tie to shallow direct hydrocarbon indicators, (3) origination from known or suspected source rock interval, (4) correlation with surface geochemical data, and (5) support by basin modeling or well data. Based on these criteria, reliable chimneys can be extracted from the seismic data as 3D geobodies. These chimney geobodies, which represent vertical hydrocarbon migration pathways, can then be superimposed on detected reservoir geobodies, which indicate possible lateral migration pathways and traps. The results can be used to assess hydrocarbon charge efficiency or risk, and top seal risk for identified traps. We investigated a case study from the Dutch North Sea in which chimney processing results exhibited vertical hydrocarbon pathways, originating in the Carboniferous age, which provided the charge to shallow Miocene gas sands and deep Triassic prospects.

Rock classification in the Haynesville Shale based on petrophysical and elastic properties estimated from well logs

2015 ◽  
Vol 3 (1) ◽  
pp. SA65-SA75 ◽  
Author(s):  
Mehrnoosh Saneifar ◽  
Alvaro Aranibar ◽  
Zoya Heidari
Keyword(s):  
Elastic Properties ◽  
Physical Models ◽  
Well Logs ◽  
Rock Properties ◽  
Fracture Treatment ◽  
Well Log ◽  
Rock Classification ◽  
Classification Techniques ◽  
Shale Reservoirs ◽  
Organic Shale

Rock classification can enhance fracture treatment design for successful field developments in organic-shale reservoirs. The petrophysical and elastic properties of formations are important to consider when selecting the best candidate zones for fracture treatment. Rock classification techniques based on well logs can be advantageous compared to conventional ones based on cores, and they enable depth-by-depth formation characterization. We developed and evaluated three rock classification techniques in organic-shale formations that incorporate well logs and well-log-based estimates of elastic properties, petrophysical properties, mineralogy, and organic richness. The three rock classification techniques include (1) a 3D crossplot analysis of organic richness, volumetric concentrations of minerals, and rock brittleness index, (2) an unsupervised artificial neural network (ANN), built from an input of well logs, and (3) an unsupervised ANN, constructed using an input of well-log-based estimates of petrophysical, compositional, and elastic properties. A so-called self-consistent approximation rock-physics model is used to estimate elastic rock properties. This model enables assessment of the elastic properties based on the well-log-derived estimates of mineralogy and shapes of rock components, in the absence of acoustic-wave velocity logs. Finally, we apply the three proposed techniques to the Haynesville Shale for rock classification. We verify the identified rock types using thin-section images and previously identified lithofacies. We determined that well logs can be directly used for rock classification instead of petrophysical, compositional, and elastic properties obtained from well-log interpretation. Direct use of well logs, instead of well-log-derived properties, can reduce uncertainty associated with the physical models used to estimate elastic moduli and petrophysical/compositional properties. The three proposed well-log-based rock classification techniques can potentially enhance fracture treatment for production from complex organic-shale reservoirs through (1) detecting the best candidate zones for fracture treatment and (2) optimizing the number of required fracture stages.

Petroleum system modeling and assessment of the remaining hydrocarbon potential in the eastern part of Drava Depression

2018 ◽  
Vol 6 (1) ◽  
pp. SB11-SB21 ◽  
Author(s):  
Marko Cvetković ◽  
Ivona Emanović ◽  
Andrej Stopar ◽  
Petra Slavinić
Keyword(s):  
Source Rock ◽  
Pannonian Basin ◽  
System Modeling ◽  
Organic Content ◽  
Petroleum System ◽  
Rock Properties ◽  
Hydrocarbon Potential ◽  
Levels Of Detail ◽  
Petroleum System Modeling

The eastern part of the Drava Depression presents a relatively small part within the Croatian part of the Pannonian Basin. A confined part within the eastern part of the Drava Depression with a working petroleum system but few hydrocarbon accumulations was selected for the evaluation of the remaining hydrocarbon potential. Four subsurface models were built with different levels of detail on which determination of source rock maturity, assessment of potential, and finally, volumes of the potentially accumulated hydrocarbons were estimated. In addition, several case scenarios, regarding source rock properties and boundary conditions were addressed to present the risk points in the model. Results proved that the amounts of hydrocarbons generated ([Formula: see text] of oil and [Formula: see text] of gas) and accumulated ([Formula: see text] of oil and [Formula: see text] of gas) in the subsurface strongly support further exploration efforts even for the conservative modeling parameters (low heat flow [HF] and moderate total organic carbon values). A set of scenarios was also modeled including different HF, total organic content, and kinetic values each with significant impact for the final model result.

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