Geochemical modelling of diagenetic reactions in a sub-arkosic sandstone

Clay Minerals ◽  
2000 ◽  
Vol 35 (1) ◽  
pp. 57-67 ◽  
Author(s):  
S. A. Barclay ◽  
R. H. Worden
Keyword(s):  
Source Rock ◽  
Upper Jurassic ◽  
Path Model ◽  
Geochemical Data ◽  
Oil Generation ◽  
Northern North Sea ◽  
Corroborative Evidence ◽  
Mineral Cements ◽  
Diagenetic Reactions ◽  
Arkosic Sandstone

AbstractA reaction path model was constructed in a bid to simulate diagenesis in the Magnus Sandstone, an Upper Jurassic turbidite reservoir in the Northern North Sea, UKCS. The model, involving a flux of source rock-derived CO2 into an arkosic sandstone, successfully reproduced simultaneous dissolution of detrital K-feldspar and growth of authigenic quartz, ankerite and illite. Generation of CO2 occurred before and during the main phase of oil generation linking source rock maturation with patterns of diagenesis in arkosic sandstones and limiting this type of diagenesis to the earlier stages of oil charging. Independent corroborative evidence for the model is provided by formation water geochemical data, carbon isotope data from ankerite and produced gas phase CO2 and the presence of petroleum inclusions within the mineral cements. The model involves a closed system with respect to relatively insoluble species such as SiO2 and Al2O3 but is an open system with respect to CO2. There are up to seven possible rate-controlling steps including: influx of CO2, dissolution of K-feldspar, precipitation of quartz, ankerite and illite, diffusive transport of SiO2 and Al2O3 from the site of dissolution to the site of precipitation and possibly the rate of influx of Mg2+ and Ca2+. Given the large number of possible controls, and contrary to modern popular belief, the rate of quartz precipitation is thus not always rate limiting.

scholarly journals Petroleum geochemical aspects of the Mandawa Basin, coastal Tanzania: the origin of migrated oil occurring today as partly biodegraded bitumen

2019 ◽  
Vol 27 (1) ◽  
pp. petgeo2019-050
Author(s):  
Tesfamariam Berhane Abay ◽  
Katrine Fossum ◽  
Dag Arild Karlsen ◽  
Henning Dypvik ◽  
Lars Jonas Jørgensen Narvhus ◽  
...  
Keyword(s):  
Source Rock ◽  
Vitrinite Reflectance ◽  
Upper Jurassic ◽  
Petroleum System ◽  
Geochemical Data ◽  
Petroleum Systems ◽  
Wet Gas ◽  
Depositional System ◽  
Marine Algal ◽  
Gas Fields

The shallow-marine Upper Jurassic–Lower Cretaceous sedimentary successions of the Mandawa Basin, coastal Tanzania, are located about 80 km away from the offshore gas discoveries of Block 2, Tanzania. In this paper we present petroleum geochemical data, including bitumen extracted from outcrop samples which are relevant to the understanding of the onshore ‘Petroleum System’ and possibly also to the offshore basin. Despite some biodegradation and weathering, common to all outcrop samples, most bitumen samples analysed contain mature migrated oil. The maturity span of geomarkers (C13–C15 range) covers the entire oil and condensate/wet gas window (Rc = 0.7–2% Rc, where Rc is the calculated vitrinite reflectance), with the biomarkers generally indicating the oil window (Rc = 0.7–1.3% Rc). This suggests that the bitumen extracts represent several phases of migrated oil and condensate, which shows that the samples are part of an active or recently active migration regime or ‘Petroleum System’. The source-rock facies inferred for the bitumen is Type II/III kerogen of siliciclastic to carbonate facies. This is oil-prone kerogen, typical for a marine depositional system with an influx of proximal-derived terrigenous material blended in with in situ marine algal organic matter (OM). Application of age-specific biomarkers such as the C28/C29-steranes, extended tricyclic terpane ratio (ETR), nordiacholestanes and the aromatic steroids suggest that more than one source rock have contributed to the bitumen. Possible ages are limited to the Mesozoic (i.e. excluding the Late Paleozoic), with the most likely source rock belonging to the Early Jurassic. More geochemical and geological studies should be undertaken to further develop the general understanding of the petroleum system of the Mandawa Basin and its implications to the ‘Petroleum Systems’ both offshore and onshore. This paper also presents a reinterpretation of published gas composition and isotope data on the Pande, Temane and Inhassoro gas fields (Mozambique) with implications for possible oil discoveries in the gas-dominated region.

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.

scholarly journals Petroleum system analysis of the Mishrif reservoir in the Ratawi, Zubair, North and South Rumaila oil fields, southern Iraq

GeoArabia ◽  
2009 ◽  
Vol 14 (4) ◽  
pp. 91-108 ◽  
Author(s):  
Thamer K. Al-Ameri ◽  
Amer Jassim Al-Khafaji ◽  
John Zumberge
Keyword(s):  
Source Rock ◽  
Lower Cretaceous ◽  
System Analysis ◽  
Isotopic Analysis ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Core Samples ◽  
Biomarker Analysis ◽  
Sulaiy Formation ◽  
Rock Analysis

ABSTRACT Five oil samples reservoired in the Cretaceous Mishrif Formation from the Ratawi, Zubair, Rumaila North and Rumaila South fields have been analysed using Gas Chromatography – Mass Spectroscopy (GC-MS). In addition, fifteen core samples from the Mishrif Formation and 81 core samples from the Lower Cretaceous and Upper Jurassic have been subjected to source rock analysis and palynological and petrographic description. These observations have been integrated with electric wireline log response. The reservoirs of the Mishrif Formation show measured porosities up to 28% and the oils are interpreted as being sourced from: (1) Type II carbonate rocks interbedded with shales and deposited in a reducing marine environment with low salinity based on biomarkers and isotopic analysis; (2) Upper Jurassic to Lower Cretaceous age based on sterane ratios, analysis of isoprenoids and isotopes, and biomarkers, and (3) Thermally mature source rocks, based on the biomarker analysis. The geochemical analysis suggests that the Mishrif oils may have been sourced from the Upper Jurassic Najma or Sargelu formations or the Lower Cretaceous Sulaiy Formation. Visual kerogen assessment and source rock analysis show the Sulaiy Formation to be a good quality source rock with high total organic carbon (up to 8 wt% TOC) and rich in amorphogen. The Lower Cretaceous source rocks were deposited in a suboxic-anoxic basin and show good hydrogen indices. They are buried at depths in excess of 5,000 m and are likely to have charged Mishrif reservoirs during the Miocene. The migration from the source rock is likely to be largely vertical and possibly along faults before reaching the vuggy, highly permeable reservoirs of the Mishrif Formation. Structural traps in the Mishrif Formation reservoir are likely to have formed in the Late Cretaceous.

Petroleum systems and results of exploration on the Atlantic margins of the UK, Faroes & Ireland: what have we learnt?

2016 ◽  
Vol 8 (1) ◽  
pp. 187-197 ◽  
Author(s):  
Iain C. Scotchman ◽  
Anthony G. Doré ◽  
Anthony M. Spencer
Keyword(s):  
Upper Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
Gas Field ◽  
Petroleum Systems ◽  
Unknown Source ◽  
Porcupine Basin ◽  
Break Up ◽  
Northern North Sea ◽  
The Uk

AbstractThe exploratory drilling of 200 wildcat wells along the NE Atlantic margin has yielded 30 finds with total discovered resources of c. 4.1×109 barrels of oil equivalent (BOE). Exploration has been highly concentrated in specific regions. Only 32 of 144 quadrants have been drilled, with only one prolific province discovered – the Faroe–Shetland Basin, where 23 finds have resources totalling c. 3.7×109 BOE. Along the margin, the pattern of discoveries can best be assessed in terms of petroleum systems. The Faroe–Shetland finds belong to an Upper Jurassic petroleum system. On the east flank of the Rockall Basin, the Benbecula gas and the Dooish condensate/gas discoveries have proven the existence of a petroleum system of unknown source – probably Upper Jurassic. The Corrib gas field in the Slyne Basin is evidence of a Carboniferous petroleum system. The three finds in the northern Porcupine Basin are from Upper Jurassic source rocks; in the south, the Dunquin well (44/23-1) suggests the presence of a petroleum system there, but of unknown source. This pattern of petroleum systems can be explained by considering the distribution of Jurassic source rocks related to the break-up of Pangaea and marine inundations of the resulting basins. The prolific synrift marine Upper Jurassic source rock (of the Northern North Sea) was not developed throughout the pre-Atlantic Ocean break-up basin system west of Britain and Ireland. Instead, lacustrine–fluvio-deltaic–marginal marine shales of predominantly Late Jurassic age are the main source rocks and have generated oils throughout the region. The structural position, in particular relating to the subsequent Early Cretaceous hyperextension adjacent to the continental margin, is critical in determining where this Upper Jurassic petroleum system will be most effective.

The source rock potential of the Upper Jurassic– lowermost Cretaceous in the Danish and southern Norwegian sectors of the Central Graben, North Sea

First Break ◽  
2013 ◽  
Vol 31 (1971) ◽  
Author(s):  
H.I. Petersen ◽  
A.C. Holme ◽  
C. Andersen ◽  
M.F. Whitaker ◽  
H.P. Nytoft ◽  
...  
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Upper Jurassic

Illite-smectite diagenesis and palaeotemperatures in Northern North Sea Quaternary to Mesozoic shale sequences

Clay Minerals ◽  
1988 ◽  
Vol 23 (2) ◽  
pp. 109-132 ◽  
Author(s):  
M. J. Pearson ◽  
J. S. Small
Keyword(s):  
North Sea ◽  
Vitrinite Reflectance ◽  
Chemical Analyses ◽  
X Ray Diffraction ◽  
X Ray ◽  
Oil Generation ◽  
Heating Event ◽  
Moray Firth ◽  
Northern North Sea ◽  
Reflectance Measurements

AbstractClay mineral abundances and illite-smectite (I/S) compositions have been determined by X-ray diffraction (XRD) in shales of Permo-Triassic to Quaternary age from seven wells in the Viking Graben and Moray Firth. Chemical analyses of size fractions provide evidence that diagenetic illitization of smectite has occurred during burial by uptake of Al and K, and release of Si. K-feldspar was probably the main source of K for illitization. The depth at which random I/S disappears occurs at similar temperatures (mean 93°C) in each well for which reliable measurements are available. Vitrinite reflectance measurements at this depth are also similar (mean 0·64% R0) and correspond to early oil generation. I/S diagenetic levels may have been imprinted by a Tertiary heating event.

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