Tectono-sedimentary evolution and source rock distribution of the mid to Late Cretaceous succession in the Great South Basin, New Zealand

2014 ◽  
Vol 54 (1) ◽  
pp. 259 ◽  
Author(s):  
Tusar Sahoo ◽  
Peter King ◽  
Kyle Bland ◽  
Dominic Strogen ◽  
Richard Sykes ◽  
...  
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Seismic Facies ◽  
Basin Evolution ◽  
Seismic Attribute ◽  
Sequence Stratigraphic ◽  
Interval Maps ◽  
South Basin ◽  
Sedimentary Evolution ◽  
Petroleum Generation

The Great South Basin, off New Zealand’s southeast coast, has attracted renewed exploration interest from major petroleum companies since 2005. The distribution of the mid Cretaceous to Paleocene source rocks (coals and coaly mudstones) is a critical component in evaluating basin prospectivity. This paper delineates source rock distribution from seismic facies characterisation, and presents a series of updated paleogeographic maps over the initial (Cretaceous) phases of basin evolution. Basin evolution has been analysed from mapped sequence stratigraphic boundaries and isochron maps. Seismic facies were characterised based on the amplitude, continuity, and stacking pattern of the reflection packages. The identified facies were calibrated with well data for age, gross lithology, and gross depositional environment. Areas of source rock deposition were demarcated using seismic attribute interval maps, from which a series of updated paleogeographic maps was prepared. Four second-order sequences have been identified within the Cretaceous succession. The lower two sequences are mainly fault bounded and were deposited in a syn-rift phase. In contrast, the upper two sequences reflect a change in basin character from rifting to a post-rift thermal sag phase. Source facies within both the syn- and post-rift sequences were deposited in mainly non-marine to marginal marine settings, although there is also the possibility of lacustrine source rocks in isolated syn-rift depocentres. The wide geographic spread of source rock intervals within the Cretaceous sequences allows for a variety of petroleum generation and exploration play scenarios.

Late Cretaceous – Tertiary sediments offshore central West Greenland: lithostratigraphy, sedimentary evolution, and petroleum potential

1985 ◽  
Vol 22 (7) ◽  
pp. 1001-1019 ◽  
Author(s):  
Flemming Rolle
Keyword(s):  
Upper Cretaceous ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Shallow Marine ◽  
West Greenland ◽  
Reservoir Rocks ◽  
Sedimentary Sequences ◽  
Sedimentary Evolution ◽  
Petroleum Generation ◽  
Exploratory Wells

Five dry exploratory wells were drilled through Upper Cretaceous and Tertiary sediments on the West Greenland shelf in 1976 and 1977. Two of these entered Precambrian basement, two bottomed in Paleocene or Upper Cretaceous basalt, and one in Campanian mudstone. On the basis of samples and logs supplied to the Geological Survey of Greenland the sedimentary sequence has been divided into seven new formations: the Campanian Narssarmiut Formation, consisting of coarse basement wash and black mudstone; the Campanian to Eocene Ikermiut Formation, consisting of marine organic-rich mudstone; the Upper Paleocene to Eocene Hellefisk Formation, comprising shallow-marine to paralic sandstone and mudstone; the Eocene Nukik Formation, consisting of turbiditic sandstone and mudstone; the Eocene to Oligocene Kangâmiut Formation of shelf to shallow-marine clean and argillaceous sandstone; the Oligocene to Neogene Manîtsoq Formation, consisting of coarse paralic to fan delta sandstone; and the Neogene Ataneq Formation, consisting of protected shallow-marine mudstone.The sedimentary evolution of the area fits well with earlier proposed models for the tectonic evolution of the Baffin Bay–Labrador Sea region.Potential petroleum source rocks are present in the Upper Cretaceous to Paleocene mudstone, and, even though they are largely immature in the drilled sections, they are expected to have entered the petroleum generation zone in the deeper parts of the basin. Their potential is mainly for gas, but some oil potential is also present. No reservoir rocks were encountered in the deeper parts of the sedimentary sequences, and the porous sandstones that occur higher in the sequence lack seals.

scholarly journals 3D-Basin Modelling of the Lishui Sag: Research of Hydrocarbon Potential, Petroleum Generation and Migration

Energies ◽  
2019 ◽  
Vol 12 (4) ◽  
pp. 650 ◽  
Author(s):  
Jinliang Zhang ◽  
Jiaqi Guo ◽  
Jinshui Liu ◽  
Wenlong Shen ◽  
Na Li ◽  
...  
Keyword(s):  
Source Rock ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Three Dimensional ◽  
Source Rocks ◽  
Rock Properties ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Accumulation ◽  
Southeastern Part ◽  
Petroleum Generation

The Lishui Sag is located in the southeastern part of the Taibei Depression, in the East China Sea basin, where the sag is the major hydrocarbon accumulation zone. A three dimensional modelling approach was used to estimate the mass of petroleum generation and accumulated during the evolution of the basin. Calibration of the model, based on measured maturity (vitrinite reflectance) and borehole temperatures, took into consideration two main periods of erosion events: a late Cretaceous to early Paleocene event, and an Oligocene erosion event. The maturation histories of the main source rock formations were reconstructed and show that the peak maturities have been reached in the west central part of the basin. Our study included source rock analysis, measurement of fluid inclusion homogenization temperatures, and basin history modelling to define the source rock properties, the thermal evolution and hydrocarbon generation history, and possible hydrocarbon accumulation processes in the Lishui Sag. The study found that the main hydrocarbon source for the Lishui Sag are argillaceous source rocks in the Yueguifeng Formation. The hydrocarbon generation period lasted from 58 Ma to 32 Ma. The first period of hydrocarbon accumulation lasted from 51.8 Ma to 32 Ma, and the second period lasted from 23 Ma to the present. The accumulation zones mainly located in the structural high and lithologic-fault screened reservoir filling with the hydrocarbon migrated from the deep sag in the south west direction.

A HYDROCARBON GENERATION MODEL FOR THE COOPER AND EROMANGA BASINS

2003 ◽  
Vol 43 (1) ◽  
pp. 433 ◽  
Author(s):  
I. Deighton ◽  
J.J. Draper ◽  
A.J. Hill ◽  
C.J. Boreham
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Generation Model ◽  
Hydrocarbon Generation ◽  
Control Points ◽  
Seismic Structure ◽  
Dynamic Topography ◽  
Late Tertiary ◽  
Petroleum Generation ◽  
Eromanga Basin

The aim of the National Geoscience Mapping Accord Cooper-Eromanga Basins Project was to develop a quantitative petroleum generation model for the Cooper and Eromanga Basins by delineating basin fill, thermal history and generation potential of key stratigraphic intervals. Bio- and lithostratigraphic frameworks were developed that were uniform across state boundaries. Similarly cross-border seismic horizon maps were prepared for the C horizon (top Cadna-owie Formation), P horizon (top Patchawarra Formation) and Z horizon (base Eromanga/Cooper Basins). Derivative maps, such as isopach maps, were prepared from the seismic horizon maps.Burial geohistory plots were constructed using standard decompaction techniques, a fluctuating sea level and palaeo-waterdepths. Using terrestrial compaction and a palaeo-elevation for the Winton Formation, tectonic subsidence during the Winton Formation deposition and erosion is the same as the background Eromanga Basin trend—this differs significantly from previous studies which attributed apparently rapid deposition of the Winton Formation to basement subsidence. A dynamic topography model explains many of the features of basin history during the Cretaceous. Palaeo-temperature modelling showed a high heatflow peak from 90–85 Ma. The origin of this peak is unknown. There is also a peak over the last two–five million years.Expulsion maps were prepared for the source rock units studied. In preparing these maps the following assumptions were made:expulsion is proportional to maturity and source rock richness;maturity is proportional to peak temperature; andpeak temperature is proportional to palaeo-heatflow and palaeo-burial.The geohistory modelling involved 111 control points. The major expulsion is in the mid-Cretaceous with minor amounts in the late Tertiary. Maturity maps were prepared by draping seismic structure over maturity values at control points. Draping of maturity maps over expulsion values at the control points was used to produce expulsion maps. Hydrocarbon generation was calculated using a composite kerogen kinetic model. Volumes generated are theoretically large, up to 120 BBL m2 of kitchen area at Tirrawarra North. Maps were prepared for the Patchawarra and Toolachee Formations in the Cooper Basin and the Birkhead and Poolowanna Formations in the Eromanga Basins. In addition, maps were prepared for Tertiary expulsion. The Permian units represent the dominant source as Jurassic source rocks have only generated in the deepest parts of the Eromanga Basin.

scholarly journals Geophysical Prediction Technology Based on Organic Carbon Content in Source Rocks of the Huizhou Sag, the South China Sea

2017 ◽  
Vol 24 (s2) ◽  
pp. 4-13 ◽  
Author(s):  
Wei Yang ◽  
Xiao-xing Gong ◽  
Fei-fei Peng
Keyword(s):  
Organic Carbon ◽  
Carbon Content ◽  
Linear Relationship ◽  
Assessment Method ◽  
Seismic Inversion ◽  
Source Rocks ◽  
Seismic Facies ◽  
Organic Carbon Content ◽  
Seismic Attribute ◽  
Regional Prediction

Abstract Due to the high exploration cost, limited number of wells for source rocks drilling and scarce test samples for the Total Organic Carbon Content (TOC) in the Huizhou sag, the TOC prediction of source rocks in this area and the assessment of resource potentials of the basin are faced with great challenges. In the study of TOC prediction, predecessors usually adopted the logging assessment method, since the data is only confined to a “point” and the regional prediction of the source bed in the seismic profile largely depends on the recognition of seismic facies, making it difficult to quantify TOC. In this study, we combined source rock geological characteristics, logging and seismic response and built the mathematical relation between quasi TOC curve and seismic data based on the TOC logging date of a single well and its internal seismic attribute. The result suggested that it was not purely a linear relationship that was adhered to by predecessors, but was shown as a complicated non-linear relationship. Therefore, the neural network algorithm and SVMs were introduced to obtain the optimum relationship between the quasi TOC curve and the seismic attribute. Then the goal of TOC prediction can be realized with the method of seismic inversion.

Petroleum generation and expulsion characteristics of Lower and Middle Jurassic source rocks on the southern margin of Junggar Basin, northwest China: implications for unconventional gas potential

2014 ◽  
Vol 51 (6) ◽  
pp. 537-557 ◽  
Author(s):  
Jigang Guo ◽  
Xiongqi Pang ◽  
Fengtao Guo ◽  
Xulong Wang ◽  
Caifu Xiang ◽  
...  
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Middle Jurassic ◽  
Junggar Basin ◽  
Northwest China ◽  
Source Rocks ◽  
Coal Bed ◽  
Southern Margin ◽  
Petroleum Generation ◽  
Gas Potential

Jurassic strata along the southern margin of Junggar Basin are important petroleum system elements for exploration in northwest China. The Lower and Middle Jurassic source rock effectiveness has been questioned as exploration progresses deeper into the basin. These source rocks are very thick and are distributed widely. They contain a high total organic carbon composed predominantly of Type III kerogen, with some Type II kerogen. Our evaluation of source rock petroleum generation characteristics and expulsion history, including one-dimensional basin modeling, indicates that Jurassic source rocks are gas prone at deeper depths. They reached peak oil generation during the Early Cretaceous and began to generate gas in the Late Cretaceous. Gas generation peaked in the Paleogene–Neogene. Source rock shales and coals reached petroleum expulsion thresholds at thermal maturities of 0.8% and 0.75% vitrinite reflectance, respectively, when the petroleum expulsion efficiency was ∼40%. The petroleum generated and expelled from these source rocks are 3788.75 × 108 and 1507.55 × 108 t, respectively, with a residual 2281.20 × 108 t retained in the source rocks. In these tight reservoirs, a favorable stratigraphic relationship (where tight sandstone reservoirs directly overlie the source rocks) indicates short vertical and horizontal migration distances. This indicates the potential for a large, continuous, tight-sand gas resource in the Lower and Middle Jurassic strata. The in-place natural gas resources in the Jurassic reservoirs are up to 5.68 × 1012 − 15.14 × 1012 m3. Jurassic Badaowan and Xishanyao coals have geological characteristics that are favorable for coal-bed methane resources, which have an in-place resource potential between 3.60 × 1012 and 11.67 × 1012 m3. These Lower and Middle Jurassic strata have good shale gas potential compared with active US shale gas, and the inferred in-place shale gas resources in Junggar Basin are between 20.73 × 1012 and 113.89 × 1012 m3. This rich inferred conventional and unconventional petroleum resource in tight-sand, coal-bed, and shale gas reservoirs makes the deeper Jurassic strata along the southern margin of Junggar Basin a prospective target for future exploration.

scholarly journals Geochemical characteristics and origin of hydrocarbons in the Mesoproterozoic reservoirs in the Liaoxi Depression, NE China

2019 ◽  
Vol 38 (2) ◽  
pp. 333-347 ◽  
Author(s):  
Youjun Tang ◽  
Meijun Li ◽  
Qiuge Zhu ◽  
Daxiang He ◽  
Xingchao Jiang ◽  
...  
Keyword(s):  
Molecular Marker ◽  
Source Rock ◽  
Middle Jurassic ◽  
Distribution Patterns ◽  
Geochemical Characteristics ◽  
Oil Reservoirs ◽  
Source Rocks ◽  
Ne China ◽  
Normal Alkanes ◽  
Petroleum Generation

Oil reservoirs have been discovered in the Mesoproterozoic strata in the Liaoxi Depression, NE China. In order to determine the source of oil shows of the Mesoproterozoic Gaoyuzhuang Formation and their organic geochemical characteristics, eight source rocks and reservoir cores from the Mesoproterozoic Gaoyuzhuang Formation and four source rocks from the overlying Middle Jurassic Haifanggou Formation were geochemically analysed. The distribution patterns of normal alkanes, acyclic isoprenoids, hopanes, steranes and triaromatic steroids of the Mesoproterozoic hydrocarbons from Well N-1 are consistent with those of source rock extracts from the Mesoproterozoic Gaoyuzhuang Formation in the Well L-1. The molecular marker compositions of source rock extracts from the overlying Middle Jurassic Haifanggou Formation are distinctively different from those of the Mesoproterozoic hydrocarbons. The results suggest that the Mesoproterozoic source rocks have significant petroleum generation potential. The Mesoproterozoic paleo-reservoir may be prospecting exploration targets in the Liaoxi Depression, NE China.

scholarly journals Evaluation of the quality, thermal maturity and distribution of potential source rocks in the Danish part of the Norwegian–Danish Basin

2008 ◽  
Vol 16 ◽  
pp. 1-66 ◽  
Author(s):  
Henrik I. Petersen ◽  
Lars H. Nielsen ◽  
Jørgen A. Bojesen-Koefoed ◽  
Anders Mathiesen ◽  
Lars Kristensen ◽  
...  
Keyword(s):  
Source Rock ◽  
Early Cretaceous ◽  
Middle Jurassic ◽  
Upper Cretaceous ◽  
Vitrinite Reflectance ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Thermal Maturity ◽  
Potential Source ◽  
Petroleum Generation

The quality, thermal maturity and distribution of potential source rocks within the Palaeozoic–Mesozoic succession of the Danish part of the Norwegian-Danish Basin have been evaluated on the basis of screening data from over 4000 samples from the pre-Upper Cretaceous succession in 33 wells. The Lower Palaeozoic in the basin is overmature and the Upper Cretaceous – Cenozoic strata have no petroleum generation potential, but the Toarcian marine shales of the Lower Jurassic Fjerritslev Formation (F-III, F-IV members) and the uppermost Jurassic – lowermost Cretaceous shales of the Frederikshavn Formation may qualify as potential source rocks in parts of the basin. Neither of these potential source rocks has a basinwide distribution; the present occurrence of the Lower Jurassic shales was primarily determined by regional early Middle Jurassic uplift and erosion. The generation potential of these source rocks is highly variable. The F-III and F-IV members show significant lateral changes in generation capacity, the best-developed source rocks occurring in the basin centre. The combined F-III and F-IV members in the Haldager-1, Kvols-1 and Rønde-1 wells contain 'net source-rock' thicknesses (cumulative thickness of intervals with Hydrogen Index (HI)> 200 mg HC/g TOC) of 40 m, 83 m, and 92 m, respectively, displaying average HI values of 294, 369 and 404 mg HC/g TOC. The Mors-1 well contains 123 m of 'net source rock' with an average HI of 221 mg HC/g TOC. Parts of the Frederikshavn Formation possess a petroleum generation potential in the Hyllebjerg-1, Skagen-2, Voldum-1 and Terne-1 wells, the latter well containing a c. 160 m thick highly oil-prone interval with an average HI of 478 mg HC/g TOC and maximum HI values> 500 mg HC/g TOC.The source-rock evaluation suggests that a Mesozoic petroleum system is the most likely in the study area. Two primary plays are possible: (1) the Upper Triassic – lowermost Jurassic Gassum play, and (2) the Middle Jurassic Haldager Sand play. Potential trap structures are widely distributed in the basin, most commonly associated with the flanks of salt diapirs. The plays rely on charge from the Lower Jurassic (Toarcian) or uppermost Jurassic – lowermost Cretaceous shales. Both plays have been tested with negative results, however, and failure is typically attributed to insufficient maturation (burial depth) of the source rocks. This maturation question has been investigated by analysis of vitrinite reflectance data from the study area, corrected for post-Early Cretaceous uplift. A likely depth to the top of the oil window (vitrinite reflectance = 0.6%Ro) is c. 3050–3100 m based on regional coalification curves. The Frederikshavn Formation had not been buried to this depth prior to post-Early Cretaceous exhumation, and the potential source rocks of the formation are thermally immature in terms of hydrocarbon generation. The potential source rocks of the Fjerritslev Formation are generally immature to very early mature. Mature source rocks in the Danish part of the Norwegian–Danish Basin are thus dependent on local, deeper burial to reach the required thermal maturity for oil generation. Such potential kitchen areas with mature Fjerritslev Formation source rocks may occur in the central part of the study area (central–northern Jylland), and a few places offshore. These inferred petroleum kitchens are areally restricted, mainly associated with salt structures and local grabens (such as the Fjerritslev Trough and the Himmerland Graben).

scholarly journals The Upper Jurassic–Cretaceous petroleum system of southern Iraq: A 3-D basin modelling study

GeoArabia ◽  
2013 ◽  
Vol 18 (1) ◽  
pp. 179-200
Author(s):  
Qusay Abeed ◽  
Ralf Littke ◽  
Frank Strozyk ◽  
Anna K. Uffmann
Keyword(s):  
Source Rock ◽  
Lower Cretaceous ◽  
Upper Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
Maximum Temperature ◽  
Basin Modelling ◽  
Petroleum Generation ◽  
D Model ◽  
Southern Iraq

ABSTRACT A 3-D basin model of the southern Mesopotamian Basin, southern Iraq, was built in order to quantify key aspects of the petroleum system. The model is based on detailed seismic interpretation and organic geochemical data, both for source rocks and oils. Bulk kinetic analysis for three source rock samples was used to quantify petroleum generation characteristics and to estimate the temperature and timing of petroleum generation. These analyses indicate that petroleum generation from the Yamama source rock (one of the main source rocks in the study area) starts at relatively low temperatures of 70–80°C, which is typical for Type II-S kerogen at low to moderate heating rates typical of sedimentary basins. Petroleum system analysis was achieved using the results from 1-D, 2-D, and 3-D basin modelling, the latter being the major focus of this study. The 1-D model reveals that the Upper Jurassic–Lower Cretaceous sediments are now within the oil window, whereas the formations that overlie the Yamama Formation are still immature in the entire study area. Present-day temperature reflects the maximum temperature of the sedimentary sequence, which indicates that no strong regional uplift affected the sedimentary rocks in the past. The 3-D model results indicate that oil generation in the Yamama source rock already commenced in the Cretaceous. At some locations of the basin this source rock reaches a present-day maximum temperature of 140–150°C. The most common migration pathways are in the vertical direction, i.e. direct migration upward from the source rock to the reservoir. This is partly related to the fact that the Lower Cretaceous reservoir horizons in southern Iraq directly overlay the source rock.

Seismic Prediction Method for Dark Mudstone Thickness of the Second Member of the Denglouku Formation in Northern Songliao Basin

2012 ◽  
Vol 616-618 ◽  
pp. 411-420
Author(s):  
Xue Juan Zhang ◽  
Lei Zhang ◽  
Zhi Ru Yang
Keyword(s):  
Thickness Distribution ◽  
Prediction Method ◽  
Songliao Basin ◽  
Thickness Ratio ◽  
Source Rocks ◽  
Seismic Facies ◽  
Quantitative Prediction ◽  
Small Scale ◽  
Seismic Attribute ◽  
Sedimentary Characteristics

The hydrocarbon source rocks in Denglouku formation of Northern Songliao Basin are mainly the grey mudstones in Deng 2 member. Combined with well and seismic information, this paper forecasts the mudstone thickness distribution of study area applying multiple seismic attribute quantitative prediction based on sedimentary characteristics. We also predict the plane distribution of dark mudstone-mudstone thickness ratio with stratigraphic sedimentary thickness information, horizontal result of seismic facies interpretation and dark mudstone-mudstone thickness ratio materials of well point. Eventually, we obtain the plane dark mudstone prediction result. Analysis indicates that the source rocks of Deng 2 member in Northern Songliao Basin mainly consist of three larger dark mudstone development areas and other sporadic small-scale development areas adjacent, which have the maximum dark mudstone thickness of about 357m located near Songji 6 well.

Assessing source rock distribution in Heather and Draupne Formations of the Norwegian North Sea: A workflow using organic geochemical, petrophysical, and seismic character

2015 ◽  
Vol 3 (3) ◽  
pp. SV45-SV68 ◽  
Author(s):  
Balazs Badics ◽  
Anthony Avu ◽  
Sean Mackie
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Seismic Data ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Geochemical Data ◽  
Seismic Attribute ◽  
Attribute Analysis ◽  
Seismic Characterization ◽  
Petrophysical Logs

The organic-rich upper Jurassic Draupne and Heather Formations are the main proven source rocks of the Norwegian North Sea. We have developed a workflow for the organic geochemical, petrophysical, and seismic characterization of the Draupne and Heather Formation source rocks in a [Formula: see text] study area in quadrant 25 in the Viking Graben in the Norwegian North Sea. We characterized the vertical and lateral organic richness variations using biostratigraphy, organic geochemical data, and petrophysical logs. The Draupne Formation is a rich (6.5 wt.% total organic carbon [TOC], 360 HI), oil-prone, immature to early oil mature source rock, representing a 25-m-thick condensed section, partly eroded over the Utsira high and thickening to 150–300 m toward the deep grabens. The underlying Heather Formation is also an oil-prone (4.4 wt.% TOC, 270 HI), 30- to 400-m-thick, more mature source rock. To map the TOC distribution using seismic, we performed detailed seismic interpretation and seismic attribute analysis following the petrophysical calibration of TOC with the [Formula: see text] ratio and P impedance on well data. Similar patterns of low-impedance high-TOC areas highlighted and mapped from the petrophysical studies at the Heather level were also observed on seismic relative acoustic impedance and amplitude maps over the study area. The poststack seismic data conditioning (structurally orientated noise reduction) improved the quality of the input megamerge seismic data and allowed the application of colored inversion, structural and fault imaging, as well as multiattribute combination and visualization techniques, which have been efficient in highlighting the distribution of high-TOC areas, structure and fault zones within the study area.

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