scholarly journals Small Unconventional Hydrocarbon Gas Reservoirs as Challenging Energy Sources, Case Study from Northern Croatia

Energies ◽  
2021 ◽  
Vol 14 (12) ◽  
pp. 3503
Author(s):  
Tomislav Malvić ◽  
Uroš Barudžija ◽  
Borivoje Pašić ◽  
Josip Ivšinović
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Gas Reservoirs ◽  
Fine Grained ◽  
The North ◽  
Kerogen Type ◽  
Hydrocarbon Fields ◽  
Hydrocarbon Gas ◽  
Northern Croatia ◽  
Migration Pathways

Small possible hydrocarbon gas reservoirs were analysed in the Bjelovar Subdepression in Northern Croatia. This area includes the Neogene–Quaternary, mostly clastics, sequences, reaching 3000+ metres in the deepest part. The shallow south-eastern part of the Drava Depression contains a subdepression characterised with several, mostly small, discovered hydrocarbon fields, where the majority are located on the northern subdepression margin. The reason is the large distance from the main depressional migration pathways and main, deep, mature source rock depocenters. However, two promising unconventional targets were discovered inside the subdepression and both were proven by drilling. The first are source rocks of Badenian, of kerogen type III in early catagenesis, where partially inefficient expulsion probably kept significant gas volumes trapped in the source rock during primary migration. Such structures are the Western Bjelovar (or Rovišće) and the Eastern Bjelovar (or Velika Ciglena) Synclines. The second promising unconventional reservoir consists of “tight” clastic lithofacies of mostly Lower Pontian located on the north-eastern margin of the subdepression. These are fine-grained sandstones with frequent alternations in siltites, silty and clayey sandstones. They are located on secondary migration pathways, but were never evaluated as regional reservoirs, although numerous drilling tests showed gas “pockets”.

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.

ACCURATE RECOGNITION OF SOURCE ROCK CHARACTER IN THE JURASSIC OF THE NORTH WEST SHELF, WESTERN AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 289 ◽  
Author(s):  
John Scott
Keyword(s):  
Source Rock ◽  
Organic Material ◽  
Source Rocks ◽  
Higher Plant ◽  
Pyrolysis Gas ◽  
Screening Analysis ◽  
North West ◽  
The North ◽  
Potential Source Rock ◽  
Rock Eval

The main potential source rock intervals are generally well defined on the North West Shelf by screening analysis such as Rock-Eval. The type of product from the source rocks is not well defined, owing to inadequacies in current screening analysis techniques. The implications of poor definition of source type in acreage assessment are obvious. The type of product is dependent on the level of organic maturity of the source rock, the ability of products to migrate out of the source rock and on the type of organic material present. The type of kerogen present is frequently determined by Rock-Eval pyrolysis. However, Rock-Eval has severe limitations in defining product type when there is a significant input of terrestrial organic material. This problem has been recognised in Australian terrestrial/continental sequences but also occurs where marine source rock facies contain terrestrially-derived higher plant material. Pyrolysis-gas chromatography as applied to source rock analysis provides, by molecular typing, a better method of estimating the type of products of the kerogen breakdown than bulk chemical analysis such as Rock-Eval pyrolysis.

scholarly journals Organic matter identification in source and reservoir carbonate in the Lower Cretaceous Mauddud Formation in Kuwait

GeoArabia ◽  
2005 ◽  
Vol 10 (4) ◽  
pp. 17-34
Author(s):  
Fowzia H. Abdullah ◽  
Bernard Carpentier ◽  
Isabelle Kowalewski ◽  
Frans van Buchem ◽  
Alain-Yves Huc
Keyword(s):  
Gas Chromatography ◽  
Organic Matter ◽  
Source Rock ◽  
Lower Cretaceous ◽  
Carbonate Rocks ◽  
Total Organic Matter ◽  
The South ◽  
Core Samples ◽  
The North ◽  
Kerogen Type

ABSTRACT The purpose of this study is to identify the source rock, reservoirs and nonproductive zones in the Lower Cretaceous Mauddud Formation in Kuwait, using geochemical methods. This formation is one of the major Cretaceous oil reservoirs. It is composed mainly of calcarenitic limestone interbedded with marl and glauconitic sands. Its thickness ranges from almost zero in the south to about 100 m (328 ft) in the north. A total of 99 core samples were collected from six oil fields in Kuwait: Raudhatain, Sabiriyah and Bahra in the north, and from the Burgan, Ahmadi and Magwa in the south. Well logs from these fields (gamma ray GR, sonic, resistivity, density) were correlated and used in the study. The core samples were screened for the amount and nature of the organic matter by Rock-Eval 6 pyrolysis (RE6) using reservoir mode. A set of samples was selected to study the properties of the organic matter including the soluble and insoluble organic parts. The geochemical characterisation was performed using different methods. After organic solvent extraction of rock samples, the solvent soluble organic matter or bitumen was characterised in terms of saturates, aromatics and heavy compounds (resins and asphaltenes). Then the hydrocarbon distribution of saturates was studied using gas chromatography (GC/FID) and gas chromatography-mass spectrometry (GC/MS) for tentative oil-source rock correlation. After mineral matrix destruction of previously extracted rocks, insoluble organic matter or kerogen was analysed for its elemental composition to identify kerogen type. The geology and the analytical results show similarities between the wells in the southern fields and the wells in the northern fields. Average Total Organic Matter (TOC) in the carbonate facies is 2.5 wt.% and the highest values (8.0 wt.%) are in the northern fields. The clastic intervals in the northern fields show higher total organic matter (1.3 wt.%) relative to the southern fields (0.6 wt.%). The total Production Index is higher in the carbonate (0.6) than the clastic section (0.3). This reflects the amount of extractable hydrocarbons, which are usually associated with the carbonate section in this formation, representing its reservoir section. Although the carbonate rocks are dominated by richer total organic matter, there are some intervals, with low total organic matter values (0.07 wt.%), representing its poor reservoir sections. The kerogen type varies between type II-III and III in the shales with a slightly better quality in the carbonate section. It is immature in almost all the studied fields. The composition of the rock extract has no relation with the rock type. Some sandstone show similar extract composition to the carbonate rocks in the reservoir intervals. The extracts from these intervals show different genetic nature than those in the shales. The maturity level in the reservoir extract is much higher than in the shale intervals. Thus, the oil accumulated in the reservoir might be largely related to migrated oil from a more mature source rock deposited in a clearly different environment than the associated shaly intervals. The best candidates being a more deeply buried Early Cretaceous Sulaiy Formation and Upper Jurassic Najmah Formation.

PETROLEUM PLAY ELEMENT PREDICTION FOR THE CRETACEOUS-TERTIARY BASIN PHASE, NORTHERN CARNARVON BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 315 ◽  
Author(s):  
K. K. Romine ◽  
J. M. Durrant ◽  
D. L. Cathro ◽  
G. Bernardel
Keyword(s):  
Focal Point ◽  
Source Rocks ◽  
Predictive Tool ◽  
Petroleum Systems ◽  
The North ◽  
Northern Carnarvon Basin ◽  
And Migration ◽  
Play Elements ◽  
Migration Pathways ◽  
Carnarvon Basin

A regional tectono-stratigraphic framework has been developed for the Cretaceous and Tertiary section in the Northern Carnarvon Basin. This framework places traditional observations in a new context and provides a predictive tool for determining the temporal occurrence and spatial distribution of the lithofacies play elements, that iss reservoir, source and seal.Two new, potential petroleum systems have been identified within the Barremian Muderong Shale and Albian Gearle Siltstone. These potential source rocks could be mature or maturing along a trend that parallels the Alpha Arch and Rankin Platform, and within the Exinouth Sub-basin.A favourable combination of reservoir and seal can be predicted for the early regressive part of the Creta- ceous-Tertiary basin phase (Campanian-Palaeocene). Lowstand and transgressive (within incised valleys) reservoirs are more likely to be isolated and encased in sealing shales, similar to lowstand reservoir facies deposited during the transgressive part of the basin phase, for example, the M. australis sand play.The basin analysis revealed the important role played by pre-existing Proterozoic-Palaeozoic lineaments during extension, and the subsequent impact on play elements, in particular, the distribution of reservoir, fluid migration, and trap development. During extension, the north-trending lineaments influenced the compart mentalisation of the Northern Carnarvon Basin into discrete depocentres. Relay ramp-style accommodation zones developed, linking the sub-basins, and acting as pathways for sediment input into the depocentres and, later in the basin's history, as probable hydrocarbon migration pathways. The relay accommodation zones are a dynamic part of the basin architecture, acting as a focal point for response to intraplate stresses and the creation, modification and destruction of traps and migration pathways.

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.

BURIAL HISTORY OF THE EASTERN OFFICER BASIN, SOUTH AUSTRALIA

1995 ◽  
Vol 35 (1) ◽  
pp. 307 ◽  
Author(s):  
R. Moussavi-Harami ◽  
D. I. Gravestock
Keyword(s):  
South Australia ◽  
Bounded Sequence ◽  
Source Rocks ◽  
Sediment Loading ◽  
Burial History ◽  
Fine Grained ◽  
Accommodation Space ◽  
The North ◽  
History Of ◽  
Well Data

The intracratonic Officer Basin of central Australia was formed during the Neoproterozoic, approximately 820 m.y. ago. The eastern third of the Officer Basin is in South Australia and contains nine unconformity-bounded sequence sets (super-sequences), from Neoproterozoic to Tertiary in age. Burial history is interpreted from a series of diagrams generated from well data in structurally diverse settings. These enable comparison between the stable shelf and co-existing deep troughs. During the Neoproterozoic, subsidence in the north (Munyarai Trough) was much higher than in either the south (Giles area) or northeast (Manya Trough). This subsidence was related to tectonic as well as sediment loading. During the Cambrian, subsidence was much higher in the northeast and was probably due to tectonic and sediment loading (carbonates over siliciclastics). During the Early Ordovician, subsidence in the north created more accommodation space for the last marine transgression from the northeast. The high subsidence rate of Late Devonian rocks in the Munyarai Trough was probably related to rapid deposition of fine-grained siliciclastic sediments prior to the Alice Springs Orogeny. Rates of subsidence were very low during the Early Permian and Late Jurassic to Early Cretaceous, probably due to sediment loading rather than tectonic sinking. Potential Neoproterozoic source rocks were buried enough to reach initial maturity at the time of the terminal Proterozoic Petermann Ranges Orogeny. Early Cambrian potential source rocks in the Manya Trough were initially mature prior to the Delamerian Orogeny (Middle Cambrian) and fully mature on the Murnaroo Platform at the culmination of the Alice Springs Orogeny (Devonian).

THE PETROLEUM GEOCHEMISTRY OF OILS AND SOURCE ROCKS FROM THE NORTHERN BONAPARTE BASIN, OFFSHORE NORTHERN AUSTRALIA

2000 ◽  
Vol 40 (1) ◽  
pp. 257 ◽  
Author(s):  
J.C. Preston ◽  
D.S. Edwards
Keyword(s):  
Source Rock ◽  
Early Cretaceous ◽  
Late Jurassic ◽  
Structural Complexity ◽  
Source Rocks ◽  
Geochemical Data ◽  
Northwestern Part ◽  
Migration Patterns ◽  
Catchment Areas ◽  
Migration Pathways

Geochemical data from oils and source rock extracts have been used to delineate the active petroleum systems of the Northern Bonaparte Basin. The study area comprises the northeastern portion of the Territory of Ashmore and Cartier Islands, and the western part of the Zone of Co-operation Area A, and is specifically concerned with the wells located on and between the Laminaria and Flamingo highs. The oils and condensates from this region can be divided into two distinct chemical groups which correspond with the reservoir types, namely, a smaller group recovered from fracture porosity within the Early Cretaceous Darwin Formation, and a larger group reservoired in sandstones of the Middle-to-Late Jurassic Plover and Elang formations. The oils recovered from the Darwin Formation have a marine source affinity and correlate with sediment extracts from the underlying Early Cretaceous Echuca Shoals Formation. The Elang/ Plover-reservoired oils, which include all the commercial accumulations, were divided into two end-member families; the first includes the relatively land-plant- influenced oils from the northwestern part of the area (e.g. Laminaria, Corallina, Buffalo and Jahal fields), the second includes the relatively marine-influenced oils to the southeast (e.g. Bayu-Undan fields). Another oil family comprises the geographically and geochemically intermediate oils of the Elang and Kakatua fields and adjacent areas. While none of the oils can be uniquely correlated with a single source unit, they show geochemical similarities with Middle-to-Late Jurassic source rock extracts. Organic-rich rocks within the Plover and Elang formations are the major source of hydrocarbons for this area. The range in geochemistry of the Elang/Plover-reservoired oils may arise from facies variation within these sediments, but is more probably due to the localised additional input of hydrocarbons generated from thermally mature organic-rich claystone seals that overlie the Elang reservoir in catchment areas and traps; i.e. from the Frigate Formation for the northwestern oil family and from the Flamingo Group for the southeastern oil family. The short-range migration patterns dictated by the structural complexity of the basin are reflected in the closeness with which variations in the geochemical character of the accumulated liquids track variations in the character of source-seal lithologies. The length of migration pathways can, therefore, be inferred from the similarity or otherwise of source-seal characters with those of the hydrocarbon accumulations themselves. The resulting observations may challenge existing ideas concerning migration patterns, hydrocarbon prospectivity and prospect risking within the Northern Bonaparte Basin.

scholarly journals Reconstruction of burial history, temperature, source rock maturity and hydrocarbon generation in the northwestern Dutch offshore

2012 ◽  
Vol 91 (4) ◽  
pp. 535-554 ◽  
Author(s):  
R. Abdul Fattah ◽  
J.M. Verweij ◽  
N. Witmans ◽  
J.H. ten Veen
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Northwestern Part ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Coal Seams ◽  
Gas Generation ◽  
Offshore Area ◽  
The North ◽  
Late Generation

Abstract3D basin modelling is used to investigate the history of maturation and hydrocarbon generation on the main platforms in the northwestern part of the offshore area of the Netherlands. The study area covers the Cleaverbank and Elbow Spit Platforms. Recently compiled maps and data are used to build the input geological model. An updated and refined palaeo water depth curve and newly refined sediment water interface temperatures (SWIT) are used in the simulation. Basal heat flow is calculated using tectonic models. Two main source rock intervals are defined in the model, Westphalian coal seams and pre-Westphalian shales, which include Namurian and Dinantian successions. The modelling shows that the pre-Westphalian source rocks entered the hydrocarbon generation window in the Late Carboniferous. In the southern and central parts of the study area, the Namurian started producing gas in the Permian. In the north, the Dinantian source rocks appear to be immature. Lower Westphalian sediments started generating gas during the Upper Triassic. Gas generation from Westphalian coal seams increased during the Paleogene and continues in present-day. This late generation of gas from Westphalian coal seams is a likely source for gas accumulations in the area.Westphalian coals might have produced early nitrogen prior to or during the main gas generation occurrence in the Paleogene. Namurian shales may be a source of late nitrogen after reaching maximum gas generating phase in the Triassic. Temperatures reached during the Mid Jurassic were sufficiently high to allow the release of non-organic nitrogen from Namurian shales.

scholarly journals Are Carboniferous coals from the Danish North Sea oil-prone?

2007 ◽  
Vol 13 ◽  
pp. 13-16 ◽  
Author(s):  
Henrik I. Petersen ◽  
Hans P. Nytoft
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Lower Carboniferous ◽  
North West ◽  
The North ◽  
Single Well ◽  
The North Sea ◽  
Clay Formation

The Central Graben in the North Sea is a mature petroleum province with Upper Jurassic – lowermost Cretaceous marine shale of the Kimmeridge Clay Formation and equivalents as the principal source rock, and Upper Cretaceous chalk as the main reservoirs. However, increasing oil prices and developments in drilling technologies have made deeper plays depending on older source rocks increasingly attractive. In recent years exploration activities have therefore also been directed towards deeper clastic plays where Palaeozoic deposits may act as petroleum source rocks. Carboniferous coaly sections are the most obvious source rock candidates. The gas fields of the major gas province in the southern North Sea and North-West Europe are sourced from the thick Upper Carboniferous Coal Measures, which contain hundreds of coal seams (Drozdzewski 1993; Lokhorst 1998; Gautier 2003). North of the gas province Upper Carboni-ferous coal-bearing strata occur onshore in northern England and in Scotland, but offshore in the North Sea area they have been removed by erosion. However, Lower Carboniferous strata are present offshore and have been drilled in the Witch Ground Graben and in the north-eastern part of the Forth Approaches Basin (Fig. 1A), where most of the Lower Carbon iferous sediments are assigned to the sandstone/shale-dominated Tayport For mation and to the coal-bearing Firth Coal Formation (Bruce & Stemmerik 2003). Highly oil-prone Lower Carboniferous lacustrine oil shales occur onshore in the Midland Valley, Scotland, but they have only been drilled by a single well off shore and seem not to be regionally distributed (Parnell 1988). In the southern part of the Norwegian and UK Central Graben and in the Danish Central Graben a total of only nine wells have encountered Lower Carboniferous strata, and while they may have a widespread occurrence (Fig. 1B; Bruce & Stemmerik 2003) their distribution is poorly constrained in this area. The nearly 6000 m deep Svane-1/1A well (Fig. 1B) in the Tail End Graben encountered gas and condensate at depths of 5400–5900 m, which based on carbon isotope values may have a Carboniferous source (Ohm et al. 2006). In the light of this the source rock potential of the Lower Carboniferous coals in the Gert-2 well (Fig. 1C) has recently been assessed (Petersen & Nytoft 2007).

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