Farsund Formation Research Articles

The ‘Base Cretaceous Unconformity’ in a basin-centre setting, Danish Central Graben, North Sea: A cored record of resedimentation and condensation accompanying transgression and basinal overturn

A cored section (North Jens-1) in the Danish Central Graben spans the ‘Base Cretaceous Unconformity’ (BCU) in a seismically conformable situation in a basin-centre setting. Multidisciplinary analysis of the core revealed that the apparent simplicity of the boundary in seismic profiles at this location disguises a complex, dynamic geological history. Dark, organic-rich, laminated hemipelagic/turbiditic Farsund Formation mudstones of late Ryazanian (Surites stenomphalus Zone) age are overlain by a thick slump sheet of upper Ryazanian mudstones, probably derived from relict rift-fault scarps on the basin floor. An erosionally-based gravity-flow bed (a hybrid density-flow deposit) of latest Ryazanian (Peregrinoceras albidum Zone) age forms the lowermost unit of the Valhall Formation. The lower boundary of this bed may record a minor hiatus across the stenomphalus–albidum zonal boundary and represents the BCU, compatible with seismic and log data. The hybrid bed is capped by an intensely burrowed omission surface that represents the first clear indication in this basin-centre location of watermass overturn and the demise of the stratified, poorly oxygenated basin. The biostratigraphy, ichnofabric and fauna/flora of the succeeding bioturbated marlstones and marly chalks of the lower Valhall Formation (Platylenticeras/Paratollia Zone) testify to increasingly oxygenated bottom waters and low sedimentation rates in a well-mixed, open marine, oligotrophic system; palynological data indicate that the onset of these conditions was linked to transgression. The North Jens-1 core illustrates the risk of assuming stratigraphic simplicity at the BCU surface in basin-centre, seismically conformable settings. Sedimentary reworking, already characteristic of the Farsund Formation setting, was probably exacerbated by transgressive erosion and accompanying sediment de-stabilization along the graben flanks.

Lithostratigraphic definition of the Upper Jurassic – lowermost Cretaceous (upper Volgian–Ryazanian) organic-rich and oil-prone Mandal Formation in the Danish Central Graben, North Sea

The Volgian–Ryazanian shale interval in the Norwegian Central Graben, North Sea, is assigned to the Mandal Formation. Despite shales with similar lithological and log characteristics are being present in the Danish Central Graben, the formation is not defined for this part of the Central Graben. This paper presents a new lithostratigraphic subdivision of the Upper Volgian–Upper Ryazanian interval in the Danish Central Graben, where the Mandal Formation is defined and replaces the uppermost part of the Farsund Formation in the ‘old’ lithostratigraphy. The Mandal Formation is recognized from its log character and is correlatable across the Danish Central Graben. The formation typically has high gamma-ray (GR) and resistivity readings accompanied by low velocity and density values. In basin centres it normally consists of a lower part showing an upward increase in GR readings (‘warming-up’ interval), an overlying interval with conspicuous high GR readings (Bo Member), and an upper heterogeneous shale interval. The base of the Mandal Formation can be seismically mapped in most of the Danish Central Graben. The upper boundary of the formation, corresponding to the Base Cretaceous Unconformity (BCU) at the transition to the Lower Cretaceous, can likewise be seismically mapped throughout the basin. The Mandal Formation is developed with thick successions in basin depocentres, while it is thin or absent along inversion structures and on structural highs. The organic-rich shales of the Mandal Formation were deposited in a restricted, low-energy, oxygen-deficient/anoxic marine environment distal from any significant terrestrial influence. Along the eastern Coffee Soil Fault in the Danish Central Graben, siliciclastic deposits constituting the gravity-flow sandstones of the Poul Member interfinger with the Mandal Formation. Gravity-flow deposits formed by turbidite currents are also common throughout the Mandal Formation in basin centres. The Mandal Formation and particularly the Bo Member are highly oil-prone and contain the best source rock quality of the entire Upper Jurassic – lowermost Cretaceous shale succession in the Danish Central Graben. Interbedded potential reservoir sandstones suggest the Mandal Formation may in places be considered as an interval with hydrocarbon prospectivity, especially along the Coffee Soil Fault.

Organic matter characterization of the Lower Cretaceous tight reservoirs in the Danish North Sea

This paper presents the first detailed organic geochemistry and petrography of the Lower Cretaceous tight reservoir units from the Valdemar Field, Danish Central Graben. The Tuxen and Sola formation chalks and the interbedded argillaceous Munk Marl Bed and Fischschiefer Member, respectively, contain thermally immature marine Type II kerogen, mainly algal liptinites, degraded bituminite and late-oil solid bitumen. The more clay-rich Fischschiefer Member and Munk Marl Bed constitute a relatively efficient seal for vertical migration and have significantly higher kerogen content as compared to the more calcareous Sola and Tuxen reservoirs. Evidence for significant oil migration can be observed across all the lithounits, highest in the Tuxen Fm which also constitute the main reservoir. Microscopic observations show a widespread distribution of granular degraded bituminite, formed by microbial degradation and diagenetic alteration of liptinites, and late-oil solid bitumen precipitated from the migrated oils. Biomarkers from rock extracts indicate open-marine depositional conditions of the source rocks that charged the hydrocarbons, having a geochemical composition similar to oils charged from the Upper Jurassic–lowermost Cretaceous Farsund Formation. The solid bitumen within such heterogeneous reservoir units might influence both reservoir quality and petrophysical properties.

Characterization and origin of large Campanian depressions within the Chalk Group of the Danish Central Graben – implications for hydrocarbon exploration and development

Abstract This study re-examines large and deep U-shaped reflections (2–4 km wide and 100–200 m deep) within the Upper Cretaceous–Danian Chalk Group in the inverted Roar Basin of the Danish North Sea, previously interpreted as a moat associated with a contour-parallel current system and/or erosive channels formed by gravity-driven turbidites. Improved 3D seismic data quality and seismic interpretation techniques helped to identify overlooked reflection terminations, which suggest that rather than a linear depression, the U-shaped reflections outline several bowl-shaped depressions. In addition, vertical high-amplitude columns and vertical discontinuity zones within and below the depressions were recognized and interpreted to indicate the presence of small fluid pipes, suggesting that the formation of the depressions is more complex. Carbon isotope analysis of high acoustic impedance beds within the underlying Lower Cretaceous chalk showed negative δ 13 C values down to −20‰, and are interpreted to indicate sediments influenced by methane-derived authigenic carbonates. Permo-Triassic half-grabens seem to have been a major source of gas-bearing fluids, as evidenced by hydrocarbon leakage phenomena within Triassic–Lower Cretaceous strata. In areas where Zechstein salt is present, the leakage root lies at salt welds, causing the formation of focused seismic reflection wipe-out and dim zones. In areas where salt was absent, the leakage root comprises a much more diffuse zone across the fault boundaries of the Permo-Triassic half-graben, and gas chimneys are characterized seismically as broad vertical dim zones up to 10 km wide. Campanian inversion tectonics caused fault reactivation and several hundreds of metres of uplift in the Roar Basin, which created an instability for the trapped gas-bearing fluids. Gentle fluid venting through observed pipes caused sediment suspension and entrainment, which could be carried away by bottom-current activity, causing localized zones of non-deposition and the formation of individual depressions. This model thus does not disregard the role of bottom-current activity in the formation of the depressions, yet it includes a fluid-venting element that fits better with the architecture and overall evidence for fluid-venting features in pre-chalk strata, as well as in the Chalk Group. Importantly, it shows that prior to the thermogenic maturation of the main source rock (i.e. the Bo Member of the Farsund Formation in the Late Miocene), fluid venting had already occurred on the Late Cretaceous seafloor from deeper source rocks that are at present overmature.

TEMPORAL AND SPATIAL DISTRIBUTION OF ORIGINAL SOURCE ROCK POTENTIAL IN UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES, DANISH CENTRAL GRABEN, NORTH SEA

The Danish Central Graben, North Sea, is a mature oil‐ and gas‐producing basin in which the principal source rocks are the Upper Jurassic – lowermost Cretaceous marine shales of the Farsund Formation (Kimmeridge Clay Formation equivalent), with possible additional potential in the directly underlying Lola Formation. This study investigates the initial source rock potential of the basin by evaluating the original (back‐calculated) source rock properties (TOCo, S2o, HIo) of the shales in the Farsund and Lola Formations within a temporal and spatial framework. About 4800 samples from 81 wells regionally distributed in the Danish Central Graben were included in the study. Samples for source rock analysis were in general collected with varying sampling density from the entire shale section. The shale section has been divided into seven units (referred to as pre‐FSU1 to FSU6; FSU: Farsund Seismic Unit) which are delineated by mappable, regional‐scale seismic markers. For the pre‐FSU1 and FSU2–FSU6 units, the number of available samples ranged from 608 to 1145, while 433 samples were available for FSU1. Good source rock quality varies through space and time and reflects both the structural development of the basin and the effects of the Late Jurassic transgression, with primary kitchen areas developing in the Tail End Graben, Feda Graben, Gertrud Graben and the Rosa Basin. The source rock quality of the shales increases gradually through time and reaches a maximum in FSU6 which includes the “hot shales” of the Bo Member. The maximum source rock quality appears to correspond to an original Hydrogen Index (HIo) of approximately 675 mg HC/g TOC. The proportion of oil‐prone samples per unit (with HIo >350 mg HC/g TOC) ranges from 7 to 11% in the pre‐FSU1 to FSU2 units (Lower Kimmeridgian – Lower Volgian), increasing to 18 – 22% in FSU3 and FSU4/FSU5 (Lower Volgian – Middle Volgian), and reaching a maximum of 53% in FSU6 (Upper Volgian – Ryazanian). FSU6 is the most prolific oil‐prone source rock interval, but the presence of oil‐prone intervals in older and deeper parts of the shale succession is important for assessing the generation potential of the Upper Jurassic petroleum system. The breakdown of the Upper Jurassic – lowermost Cretaceous shale section into mappable seismic units with assigned original source rock properties will contribute to a considerably improved understanding of the temporal and spatial distributions of source rock quality in the Danish Central Graben.

Regional hydrocarbon potential and thermal reconstruction of the Lower Jurassic to lowermost Cretaceous source rocks in the Danish Central Graben

The Danish part of the Central Graben (DCG) is one of the petroliferous basins in the offshore region of north-western Europe. The source rock quality and maturity is here reviewed, based on 5556 Rock-Eval analyses and total organic carbon (TOC) measurements from 78 wells and 1175 vitrinite reflectance (VR) measurement from 55 wells, which makes this study the most comprehensive to date. The thermal maturity is evaluated through 1-D basin modelling of 46 wells. Statistical parameters describ-ing the distribution of TOC, hydrocarbon index (HI) and Tmax are presented for the Lower Jurassic marine Fjerritslev Formation, the Middle Jurassic terrestrial-paralic Bryne, Lulu, and Middle Graben Formations and the Upper Jurassic to lowermost Cretaceous marine Lola and Farsund Formations in six areas in the DCG. For the Farsund Formation the source-rock richness is presented for selected stratigraphic sequences. The upper part of the Farsund Formation is immature in the southern part of the Salt Dome Province, and late oil mature in and near the Tail End Graben and in the Søgne Basin. The lower part of the Farsund Formation is immature in local areas, yet post-mature in the Tail End Graben and in the Salt Dome Province. The Lower and Middle Jurassic shales are gas-prone in most of the DCG. The depth of the oil window, as defined by a VR of 0.6% Ro, ranges between 2200 and 4500 m. The variations are ascribed to heat flow differences in the DCG and can be modelled by a simple depth model, which includes the thickness of the Cretaceous to Palaeo-gene Chalk and Cromer Knoll Groups. According to the model, a thick Chalk Group offsets the oil window to deeper levels, which likely can be attributed to the thermal properties of the highly thermally conductive chalk compared to the underlying less thermally conductive clays. The DCG is an overpressured basin, and high-pressure, high-temperature conditions are expected to occur deeper than 3.8 km except for the Feda and Gertrud Grabens where such conditions, due to generally lower tem-peratures, are expected to occur deeper than around 4.7 km.

Organofacies composition of Upper Jurassic – lowermost Cretaceous source rocks, Danish Central Graben, and insight into the correlation to oils in the Valdemar Field

Abstract The organic-rich marine shales of the Upper Jurassic - lowermost Cretaceous Farsund Formation are the main hydrocarbon source rocks for the Cretaceous chalk reservoir of the Valdemar Field (Danish North Sea). Geochemical analyses of oil extracts from core samples across the greater Valdemar Field show substantial heterogeneity of the reservoir oils, suggesting contribution from kitchen areas with source rocks of variable organofacies and thermal maturity. In order to better understand the source rock facies that charged the field, a refined organofacies characterization of the Upper Jurassic - lowermost Cretaceous marine shale source rock succession (Farsund Formation) in the Danish Central Graben was established. This organofacies characterization is based on integration of petrographic and geochemical data and demonstrates large variations in both the regional and local distribution of the organofacies at the sequence level in the shales within the Danish Central Graben. In addition, the organofacies characterization shows that the respective sequences in the succession may be represented by several organofacies at the same time. Part of the explanation to the heterogeneity in the oil types accumulated within the Valdemar Field may lie in the presence of different organofacies within the uppermost sequences (Vol-3 to Ryaz-1) in the three kitchen areas. Each organofacies presumable generates different types of oils and the variation in the relative proportions of the different organofacies likely determines the composition of the generated oils. One dimensional (1-D) maturity modelling at three pseudo-well locations, each representing a potential Farsund Formation kitchen, shows that all kitchens are in the main oil window and that mainly oil was expelled from the Volg-3 to Ryaz-1 sequences. Modelling indicates that (i) average values of TOC, HI, thickness and the kinetic model are the main controls on generation and expulsion of hydrocarbons; and (ii) by increasing these parameters, expulsion could also occur from the lower part of the succession.

SOURCE ROCK QUALITY VARIATIONS OF UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES AND THEIR RELATIONSHIP TO OILS IN THE VALDEMAR FIELD, DANISH NORTH SEA

The main source rocks for the hydrocarbons at the Valdemar field (Danish North Sea) are the Upper Jurassic – lowermost Cretaceous organic‐rich marine shales of the Farsund Formation. However, geochemical analyses of retained petroleum in reservoir cores show variations in oil type and maturity which indicate a complex charging history. This paper reviews the organofacies and source rock quality variations in 55 samples of the Farsund Formation from the North Jens‐1 well (Valdemar field) within a sequence stratigraphic framework in order to discuss the source of the hydrocarbons. Petrographic and geochemical data, including biomarker analyses, were integrated in order to characterize the kerogen composition, original source rock potential and depositional environment of the Farsund Formation.The thermal maturity, source rock quality and kerogen quality all vary at the sequence level, and in general change upwards from early mature, primarily gas‐prone Type II kerogen in the Kimmeridgian Kimm‐2 and Kimm‐3 sequences to immature, highly oil‐prone sapropelic Type II kerogen in the Volg‐4 and Ryaz‐1 sequences (Volgian, Ryazanian). The kerogen has a maceral composition dominated by fluorescing amorphous organic matter (AOM) and liptodetrinite, with variable but generally minor amounts of terrigenous organic matter. The stratigraphic distribution of organic matter is similar to that in regional observations from the Danish Central Graben but minor differences occur, especially in the amount of fluorescing AOM in the Kimmeridgian sequences. The decrease in terrigenous input (vitrinite) upwards through the marine shale succession likely reflects a marine transgression of the Danish Central Graben area during Late Jurassic time. The source potential of the Upper Jurassic – lowermost Cretaceous shales in the North Jens‐1 well is generally lower than that observed regionally, including an absence of relatively organic‐rich, oil‐prone intervals in the older part of the succession which have been demonstrated to occur elsewhere in the Danish Central Graben. However, in agreement with the regional trend, back‐calculated source rock data and calculated Ultimate Expulsion Potentials show that the uppermost Volgian (Volg‐4) and Ryazanian (Ryaz‐1) sequences are the most oil‐prone intervals. The Ryaz‐1 sequence represents a condensed section formed during a period characterised by low sedimentation rates and high preservation of algal organic matter.Biomarker compositions from source rock extracts from the North Jens‐1 well cannot be directly correlated to Valdemar reservoir oils, suggesting that the mature organofacies which charged the oils are not represented in the samples from North Jens‐1.

Source rocks of the German Central Graben

Abstract Jurassic to Lower Cretaceous formations are the most important source rocks for hydrocarbons in the southern Central Graben area. Within the Dutch Central Graben, the Lower Jurassic Posidonia Shale Formation is the most prolific source for hydrocarbons, while the Upper Jurassic to Lowermost Cretaceous Bo Member of the Farsund Formation plays this role in the Danish Central Graben. Oil and gas discoveries in the Norwegian, Dutch and Danish part of the Central Graben proved a prolific petroleum system. Despite limited success of hydrocarbon exploration in the German part of the Central Graben, various indications suggest migration of gas out of active thermogenic source rocks that are closely related to potential shallow gas accumulations. These indications include the restricted location of the bright spots above the Jurassic graben system, the occurrence of gas chimneys underneath these accumulations and geochemical data from offshore The Netherlands, which support contribution of thermogenic gas. The purpose of this study is to assess the potential for generating thermogenic hydrocarbons from Upper Triassic to Lower Cretaceous formations. For this reason, prominent source rocks of the Southern North Sea, i.e. the Posidonia Shale Formation and the Upper Jurassic to Lower Cretaceous “Hot Shales” (namely Clay Deep Member offshore The Netherlands and Bo Member offshore Denmark), were mapped in detail. These and other potential formations from the Late Triassic to the Early Cretaceous are integrated into an existing petroleum system model of the Northern German North Sea, which was modified for the new requirements. The results showed that the main source rocks of the southern Central Graben, the Posidonia Shale Formation, and the Upper Jurassic – Lower Cretaceous “Hot Shales” are insignificant as sources for commercial hydrocarbon accumulations within the German Central Graben area. That is either due to marginal occurrence or to low maturity. However, Lower to Upper Jurassic formations such as marine claystones of the Aalburg Formation and the lower parts of the Kimmeridge Clay Formation, as well as coaly intervals of the Central Graben Subgroup, are likely to have generated, and still generate, hydrocarbons.

Preliminary assessment of dolomite stringers in the Upper Jurassic Farsund Formation as a potential unconventional hydrocarbon reservoir

Abstract With the increasing interest in the development of shale reservoirs in Europe, cross-border geoscience co-operation is undoubtedly pivotal in understanding the laterally extensive and vastly underexplored unconventional plays in and around the North Sea. The Upper Jurassic Volgian Farsund Formation is considered to be a key source rock in the North Sea. Organic-rich mudrocks are interbedded with distal silt- to sand-prone turbidites and are commonly punctuated by variably thick dolomitized stringers. The latter are locally hydrocarbon charged, and are considered to have better-preserved microporosity and pore connectivity and higher brittleness compared to the adjacent mudrocks. Hence, an improved awareness of their origin and distribution is essential to understanding this potential unconventional play. In this paper, the origin and lateral continuity of the dolomitized stringers within the Farsund Formation are considered based on the integration of borehole image, sedimentological, petrographical and geochemical data. While acknowledging the high level of uncertainty held in some aspects of this study, based on the restricted dataset, our main purpose is to share preliminary findings and thoughts, which are aimed at prompting wider cross-border discussion.

Comprehensive evolution of a petroleum system in absolute time: The example of Brynhild, Norwegian North Sea

Petroleum systems are inherently complex, comprising multiple components and processes, which variably interact in space and time to form petroleum accumulations. Improved understanding of these complex systems requires a holistic approach of integrating diverse geological, geophysical and organic and inorganic geochemical data. Here, we present an applied and comprehensive Re-Os geochronological and geochemical study on the Brynhild petroleum system from the Norwegian North Sea. Essential components of this system include shale source rocks of the Mandal and Farsund Formations, reservoir sandstones of the Ula Formation and their bitumen extracts, and produced Brynhild crude oil.Rock-Eval, trace metal and Re-Os data reveal the excellent oil-generation potential of the shaley source rocks (high contents of organic matter containing large amounts of type I kerogens) and constrain their depositional conditions (anoxic bottom waters in a high-productivity regime driven by enhanced supply of land-derived nutrients). Seven Re-Os shale ages between ~146 and ~134 Ma are consistent with existing Volgian–Ryazanian age estimates and constrain the initial 187Os/188Os of the shales to ~0.52 in the lowermost Farsund Formation and ~0.75 in the uppermost Mandal Formation. Solvent-extracted reservoir rocks of the Ula Formation contain insoluble organic matter with type III–type IV kerogens likely supplied by erosion of older (a precise 179 Ma Re-Os age with unrealistically low initial 187Os/188Os) coal-bearing sediments or organic-rich shales.The Brynhild crude oil has relatively low 187Os/188Os and a generation age of ~44 Ma based on an asphaltene-only Re-Os isochron. Maltenes from the Brynhild crude oil are isotopically affected by interaction with organic-rich source rocks that represent the seal for the Brynhild oil field. Compared with the crude oil, bitumen from Ula Formation sandstones have contrasting Re-Os properties: high 187Os/188Os ratios and young generation ages between 8 and 0 Ma based on asphaltene-bitumen-maltene Re-Os triplets, asphaltene-only Re-Os regressions, and ReOs model ages for components with extremely high 187Re/188Os. The 44 Ma and 8–0 Ma Re-Os ages agree well with regional burial models that indicate oil generation from ~44 Ma to present day. A genetic link between crude oil and bitumen is indicated by their similar alkane patterns, V and Ni contents, and V/Ni and pristane/phytane ratios. Modeling of 187Os/188Os for individual organic components through time shows that shales of the Mandal Formation developed 187Os/188Os ratios that match those of the crude oil and bitumen at ~44 Ma and ~8 Ma, respectively, and therefore confirm the source for both hydrocarbon phases. We suggest that bitumen formed during in-reservoir mixing of a ~44 Ma old early mature, asphaltene-poor oil (Brynhild crude oil) with an ~8 Ma old asphaltene-rich oil.

Temporal organic facies variations of Upper Jurassic - lowermost Cretaceous source rocks in the Danish Central Graben, North Sea

The Upper Jurassic – lowermost Cretaceous marine mudstones of the Farsund Formation constitute the principal source rocks in the Danish North Sea sector with the uppermost Bo Member considered most prolific. However, the areal distribution of the Bo Member is limited and since it is thermally immature over large areas it is unlikely that this interval has generated sufficient quantities of petroleum to fill the reservoirs in the Danish sector. In search for additional source rocks potential we have investigated the lower part of the Farsund Formation using a sequence stratigraphic framework. Organic geochemical screening and petrographic analyses of core and cuttings samples have been performed to define the source potential and map the regional distribution of organic-rich sequences in the Upper Jurassic succession. The study outlines variations of both maturity, source rock quality, and kerogen quality at sequence level with an upward improvement from poor gas-prone Type II kerogen in the Kimm-1 and Kimm-3 sequences to highly oil-prone Type II kerogen in the Volg-1, Volg-4 and Ryaz-1 sequences. The kerogen is dominated by fluorescent AOM and liptinite and structural alginite in form of Leiosphaerida- and Tasmanites-type telalginites throughout the entire succession, with vertical- and regional variations in the amount of larger Tasmanites. The study shows that the shales in Volg-1 and -3 sequences are organic-rich and oil prone with TOC > 4 wt% and HI > 340 mg HC/g TOC. Particularly the Volg-1 sequence, being the thickest and laterally most widespread forms a significant supplementary source for oil in the Danish sector.

Upper Jurassic–lowermost Cretaceous marine shale source rocks (Farsund Formation), North Sea: Kerogen composition and quality and the adverse effect of oil-based mud contamination on organic geochemical analyses

The Jude-1 well is located in the central part of the Danish Central Graben, North Sea, and was drilled into immature black shales of the Upper Jurassic–lowermost Farsund Formation, a world-class marine source rock. The well was drilled with oil-based drilling mud (OBM). The lithofacies consists of argillaceous shale, calcareous shale and dolomite stringers as confirmed by cuttings and core. A core was taken in the upper part of the formation at the beginning of a ‘hot’ argillaceous shale interval characterized by elevated TOC and HI values. Cuttings and core samples were investigated to unravel kerogen composition, source rock quality and the contamination effect of OBM on organic geochemical analyses. The organic facies of the source rocks corresponds to Type II kerogen or Organofacies B (sensu Pepper and Corvi, 1995). Considerable fluctuations in HI values through the Farsund Formation reflect pronounced variations in source rock quality, although a faint lamination of the shales and overall high TOC contents testify to prevailing oxygen-deficient depositional conditions preventing significant bioturbation and reworking of the sediment and organic matter. Petrography of core samples reveals a relatively homogenous sapropelic kerogen composition dominated by a groundmass of yellowish fluorescing amorphous organic matter and liptodetrinite intimately associated with the mineral matrix. Telalginite is less abundant, but Tasmanites- and in particular Leiosphaerida-type telalginites were observed. Minor but varying amounts of detrital terrigenous macerals suggest a considerable distance to land areas and thus limited supply of land plant-derived organic matter. The argillaceous shale lithofacies generally is more oil-prone and organic-rich than the more gas-prone calcareous shale facies. The uppermost section includes the ‘hot’ argillaceous shales, which together with two deeper argillaceous shale intervals are highly organic-rich and oil-prone. Average TOC of the ‘hot’ argillaceous shales is ~7wt% and HI reaches >500mgHC/gTOC. The total Ultimate Expulsion Potential (UEP) of the over 853m (2799ft) thick Farsund Formation is ~142mmboe/km2. Results from non-contaminated samples are thus consistent with the Farsund Formation being a world-class highly oil-prone marine source rock. The predicted oil composition corresponds to ‘paraffinic low wax oils’. The adverse effect of OBM contamination on geochemical analyses is demonstrated by Rock-Eval data and measured bulk kinetics of contaminated core samples. The measured kinetics has a considerable proportion of low activation energies related to OBM contamination which is also supported by high Production Indices. Further, gas chromatograms of the saturated fraction of extracts from contaminated cores clearly show evidence of OBM in the nC11–nC14 range. Rock-Eval S2 peaks have a ‘shoulder’ showing that the low Ea-peaks result from carry over from the S1 peak, caused by the OBM contamination. As a consequence Hydrogen Index values are increased.

OIL FAMILY TYPING, BIODEGRADATION AND SOURCE ROCK AFFINITY OF LIQUID PETROLEUM IN THE DANISH NORTH SEA

Variations in liquid petroleum compositions in the Danish Central Graben and Siri Fairway, North Sea, demonstrate the presence of several active source rock facies. To address this issue in detail, a total of 213 samples of liquid petroleum from the Danish Central Graben and the Siri Fairway were typed to eight main oil families and three sub‐families based on characteristic geochemical properties and principal component analysis (PCA). Comparison with source rock extract data made it possible to suggest correlative source rocks for each oil family together with the source rock depositional environments. The main oil families are: 1(B), 2(B), 3a(B), 3b(B), 4(B‐D/E), 5(D/E‐B), 6(D/E‐F) and 7(A), where the capital letters in brackets refer to the organofacies types of Pepper and Corvi (1995), thus directly linking the oil family type to the source rock facies. Oil families 1(B), 2(B), 3a(B) and 3b(B) were charged from marine shales (principally the Upper Jurassic Farsund Formation); oil families 4(B‐D/E) and 5(D/E‐B) are mixed petroleums with both terrigenous and marine components; oil family 6(D/E‐F) was charged from Middle Jurassic coaly units; whereas oil family 7(A) was charged from a carbonate source (Zechstein dolomites). Family 7(A) has only been documented in the form of oil stains. The most widespread oil family is 3a(B), sourced from Upper Jurassic marine shales. Charging from different organofacies is indicated by oil family 3b(B), which was derived from parts of the same shale succession which were more terrigenous‐influenced and possibly slightly more oxic; and families 2(B) and 1(B), which were sourced from more organic‐rich, anoxic parts of the shales. Mildly biodegraded oils (Level 1 to 2) appear mainly to occur in the central to southern parts of the Danish Central Graben.

Provenance of gravity-flow sandstones from the Upper Jurassic–Lower Cretaceous Farsund Formation, Danish Central Graben, North Sea

Through the Upper Jurassic and Lower Cretaceous gravity-flow sandstones were deposited in the Danish Central Graben. These gravity-flow sandstones were deposited within mudstones of the Farsund Formation which is the main source rock in the area, and they are thus potential oil and gas reservoirs. The petrography and geochemistry of the sandstones show good intra well relations and several local geographical relations, which may indicate that they were derived from multiple locally sourced flows and not merely by one basin-axial flow system. The gravity-flow sandstones deposited in the eastern part of the basin are less mature and richer in, especially, carbonates and albite compared to previously deposited Jurassic sandstones and simultaneously deposited sandstones in the western part of the Danish area. This may indicate a division of the basin in an eastern and a western provenance province. This study addresses the provenance of the gravity-flow sandstones by petrographical and geochemical analyses in order to derive possible shared detrital sources as a means of understanding the transport system(s) of the gravity flows.

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

The principal source rocks in the Danish and southern Norwegian Central Graben in the North Sea are the Upper Jurassic to lowermost Cretaceous marine shales of the Mandal and Farsund formations. The distribution of generation potential and thermal maturity is quite complex. Biomarkers of crude oils from the northern Danish Central Graben indicate correlation to the Bo Member of the upper Farsund Formation or to the lower part of the formation. Biomarker ratios of oils from the Danish Chalk reservoirs show a maturity gradation from south to north, with oils in the northern part being more mature. Vitrinite reflectance gradients show differences in depth of the ‘top oil window’. In areas characterized by HPHT conditions and thick overlying Chalk, petroleum generation is retarded and the oil window is displaced downwards by 200–350 m. Source rock quality varies. The upper part of the shales is generally considered the most oil-prone. However, analyses indicate that the lower part of the Farsund Formation may contain intervals with rich oil-prone shales. Furthermore, the petroleum generation of the Upper Jurassic shales below the Farsund Formation is often overlooked, but source rock data indicate that gas/oil-prone, and to some extent oil-prone, shales are present.

Chemostratigraphy of upper Jurassic reservoir sandstones, Danish Central Graben, North Sea

A chemostratigraphic study of Upper Jurassic sandstones in the northern Danish Central Graben has been undertaken within the framework of a well-defined stratigraphic/sedimentological model based particularly on cored well sections. Two reservoir sandstone units are recognised, the transgressive marginal marine to shoreface sandstone of the Gert Member and the regressive to transgressive shoreface sandstone of the Ravn Member. Both members belong to the Heno Formation, which is equivalent to the Fulmar Formation (UK) and the Ula Formation (Norway). Multivariate analysis of geochemical data from 264 core samples from 8 wells reveals the distinction between the two reservoir sandstones (Gert and Ravn members) and the two offshore claystones (Farsund and Lola formations). Specific elements have proven to be important for this separation and these elements demonstrate differences even in 2-dimensional cross plots. The Farsund Formation is characterised by higher V, U and P 2O 5, and lower MgO and K 2O when compared with the Lola Formation. The Gert Member typically has higher maximum amounts of Cr and TiO 2 than the Ravn Member. The high Cr and TiO 2 content (probably from chrome spinel and Ti-minerals) might be related to a source of exposed Carboniferous sediments in the Gert Ridge area. The Ravn Member is characterised by higher Na 2O, P 2O 5 and Th contents than the Gert Member, which may reflect a higher content of plagioclase (Na 2O) and a changed heavy mineral assemblage. The Mid North Sea High is a likely source for the heavy mineral suite that characterises the Ravn Member. The Rita-1 well, situated closest to the Mid North Sea High, seems to have been more influenced by this source than the other wells. In the Hejre area, a volcanic source supplying K-feldspar may be responsible for the relatively high K 2O/Al 2O 3 observed in both the Gert and Ravn members. Hence in addition to differentiation between the two reservoir sands and between the two offshore claystones, this study also illustrates the use of geochemical data for evaluation of source characteristics and dominance of different sediment source areas.

Source rock quality and maturity and oil types in the NW Danish Central Graben: implications for petroleum prospectivity evaluation in an Upper Jurassic sandstone play area

Abstract The principal exploration targets in the northwestern part of the Danish Central Graben have been Upper Jurassic sandstone reservoirs. The presence and effectiveness of the oil-generating rocks of the Upper Jurassic–lowermost Cretaceous marine shales of the Farsund Formation has generally not been considered as a significant risk. This study provides an evaluation of the source rock quality, maturity and distribution and of the oils in this area. The kerogen in the Farsund Formation is algal-derived, and kerogen type ranges from Type II to Type III. Generally the source rock quality is fair to excellent, but the petroleum generation potential varies considerably. In most wells the uppermost part of the Farsund Formation (Bo Member) consists of highly oil-prone shales. However, the presence of oil-prone kerogen may be masked by kerogen of poorer source quality. Favourable conditions for oil-prone kerogen preservation were present during the time of deposition of upper parts of the Farsund Formation, but exceptions are not unusual. Similar vitrinite reflectance gradients indicate a uniform thermal regime over the area. The oil window occurs from c . 3800–4000 to 4800 m, i.e. spanning approximately 800–1000 m. A general decrease in the generation potential from the top towards the base of the formation is caused by both generation and deterioration of kerogen quality. The Gertrud Graben and Feda Graben constitute the main kitchen areas, and oil compositions indicate sourcing from marine shales. In the shallow parts of the Outer Rough Basin the shales are mostly immature and the sourcing is dependent on kitchen areas outside the area or on Palaeozoic rocks. Mature Zechstein is indicated by a minor oil show probably locally sourced.

04/02402 Respirometric biogas measurement: Oliveri, C. Labor Praxis, 2003, 27, (5), 74–76. (In German)

The Jude-1 well is located in the central part of the Danish Central Graben, North Sea, and was drilled into immature black shales of the Upper Jurassic–lowermost Farsund Formation, a world-class marine source rock. The well was drilled with oil-based drilling mud (OBM). The lithofacies consists of argillaceous shale, calcareous shale and dolomite stringers as confirmed by cuttings and core. A core was taken in the upper part of the formation at the beginning of a ‘hot’ argillaceous shale interval characterized by elevated TOC and HI values. Cuttings and core samples were investigated to unravel kerogen composition, source rock quality and the contamination effect of OBM on organic geochemical analyses. The organic facies of the source rocks corresponds to Type II kerogen or Organofacies B (sensu Pepper and Corvi, 1995). Considerable fluctuations in HI values through the Farsund Formation reflect pronounced variations in source rock quality, although a faint lamination of the shales and overall high TOC contents testify to prevailing oxygen-deficient depositional conditions preventing significant bioturbation and reworking of the sediment and organic matter. Petrography of core samples reveals a relatively homogenous sapropelic kerogen composition dominated by a groundmass of yellowish fluorescing amorphous organic matter and liptodetrinite intimately associated with the mineral matrix. Telalginite is less abundant, but Tasmanites- and in particular Leiosphaerida-type telalginites were observed. Minor but varying amounts of detrital terrigenous macerals suggest a considerable distance to land areas and thus limited supply of land plant-derived organic matter. The argillaceous shale lithofacies generally is more oil-prone and organic-rich than the more gas-prone calcareous shale facies. The uppermost section includes the ‘hot’ argillaceous shales, which together with two deeper argillaceous shale intervals are highly organic-rich and oil-prone. Average TOC of the ‘hot’ argillaceous shales is ~ 7 wt% and HI reaches > 500 mg HC/g TOC. The total Ultimate Expulsion Potential (UEP) of the over 853 m (2799 ft) thick Farsund Formation is ~ 142 mmboe/km2. Results from non-contaminated samples are thus consistent with the Farsund Formation being a world-class highly oil-prone marine source rock. The predicted oil composition corresponds to ‘paraffinic low wax oils’. The adverse effect of OBM contamination on geochemical analyses is demonstrated by Rock-Eval data and measured bulk kinetics of contaminated core samples. The measured kinetics has a considerable proportion of low activation energies related to OBM contamination which is also supported by high Production Indices. Further, gas chromatograms of the saturated fraction of extracts from contaminated cores clearly show evidence of OBM in the nC11–nC14 range. Rock-Eval S2 peaks have a ‘shoulder’ showing that the low Ea-peaks result from carry over from the S1 peak, caused by the OBM contamination. As a consequence Hydrogen Index values are increased.

Middle Jurassic – Early Cretaceous rifting of the Danish Central Graben

During the Jurassic – Early Cretaceous, the Danish Central Graben developed as a N–S- to NNW– SSE-trending graben bounded by the Ringkøbing–Fyn High towards the east and the Mid North Sea High towards the west. The graben consists of a system of half-grabens and evolved by faultcontrolled subsidence; three main rift pulses have been recognised. The first pulse ranged from the Callovian to the Early Oxfordian, the second pulse was initiated in the latest Late Kimmeridgian and lasted for most of the Early Volgian, and the third and final pulse occurred within the Ryazanian in the Early Cretaceous. The first pulse was characterised by subsidence along N–S-trending faults. The most pronounced fault-controlled subsidence occurred in the east, especially along N–S-striking segments of the boundary fault to the Ringkøbing–Fyn High. During this period, minor salt movements occurred with the development of salt pillows. The activity along the N–S-trending faults ceased during the Oxfordian. During the second pulse, in Early Volgian times, subsidence was concentrated along new NNW–SSE-trending faults and the main depocentre shifted westward, being most marked within the Tail End Graben, the Arne–Elin Graben, and the Feda Graben. This tectonic event was accompanied by the accumulation of a relatively thick sediment load resulting in the development of salt diapirs, especially within the Salt Dome Province. The third tectonic pulse was essentially a reactivation of the NNW–SSE-trending structures and there is clear evidence of subsidence controlled by faulting and salt movements. Despite the overall extensional tectonic regime, local compressional tectonics resulted in thrusting. For instance, the Gert Ridge is interpreted to have formed by readjustment at the boundary fault between two subsiding blocks. The structural framework during graben evolution controlled, to some degree, the distribution of reservoir sandstones. Reservoir sandstones associated with periods of rotational tilt include Middle Jurassic deposits referred to the Bryne and Lulu Formations, and Upper Jurassic sandstones referred informally to the ‘Fife Sandstone Formation’. Sands deposited during tectonic relaxation are represented by the Heno Formation and Upper Jurassic turbidites interbedded in the Farsund Formation. Sea-level changes were probably most important during periods of tectonic relaxation, particularly with respect to the deposition of lowstand sandstones in basinal areas.