Lista Formation Research Articles

Anisotropic Poroelastic Modelling of Depletion-Induced Pore Pressure Changes in Valhall Overburden

Stress and pore pressure changes due to depletion of or injection into a reservoir are key elements in stability analysis of overburden shales. However, the undrained pore pressure response in shales is often neglected but needs to be considered because of their low permeability. Due to the anisotropic nature of shales, the orientation of both rock and stresses should be considered. To account for misalignment of the medium and the stress tensor, we used anisotropic poroelasticity theory to derive an angle-dependent expression for the pore pressure changes in transversely isotropic media under true-triaxial stress conditions. We experimentally estimated poroelastic pore pressure parameters of a shale from the Lista formation at the Valhall field. We combined the experimental results with finite element modelling to estimate the pore pressure development in the Valhall overburden over a period of nearly 40 years. The results indicate non-negligible pore pressure changes several hundred meters above the reservoir, as well as significant differences between pore pressure and effective stress estimates obtained using isotropic and anisotropic pore pressure parameters. We formulate a simple model approximating the undrained pore pressure response in low permeable overburden. Our results suggest that in the proximity of the reservoir the amplitude of the undrained pore pressure changes may be comparable to effective stresses. Combined with the findings of joint analysis of locations of casing deformation and total and effective stresses, the results suggest that pore pressure modelling may become an important element of casing collapse and caprock failure risk analysis and mitigation.

The Mungo Field, Blocks 22/20a and 23/16a, UK North Sea

Abstract The Mungo Field is a mature producing asset located in the UK Central North Sea. Discovered in 1989 and brought on production in 1998, it is the largest field within the Eastern Trough Area Project (ETAP). Production occurs via a normally unattended installation and is tied back to the ETAP Central Processing Facility. It is a pierced, four-way dip closure against a salt diapir. Light oil is present within steeply dipping Late Paleocene sandstone and Early Paleocene–Late Cretaceous chalk intervals. The vertical relief of the salt stock is around 1500 m TVDSS and top of the salt canopy lies at about 1350 m TVDSS. The Paleocene sandstones (Forties Sandstone Member of the Sele Formation, Lista Formation and Maureen Formation) make up the primary reservoir and have been extensively developed in three phases since 1998 under water injection and natural depletion. The sandstones were deposited as deep-water turbidite complexes (submarine fans with local channels) on and around the flanks of the rising salt diapir. More recently, successful stimulation of the Chalk Group, coupled with re-evaluation of core and well-log data, has indicated that economic production rates could also be achieved from the underlying fractured chalk reservoir.

The Kraken and Kraken North fields, Block 9/2b, UK North Sea

Abstract The Kraken and Kraken North fields lie in the UK Continental Shelf Block 9/2b on the East Shetland Platform. Hydrocarbons are stratigraphically trapped within Heimdal Sandstone Member of the Lista Formation. The fields lie at around 3900 ft true vertical; depth subsea and the oil is heavy (13–15°API) and viscous. The field is developed via a waterflood scheme with long horizontal production and injection wells, alternating across the field. To date, 21 development wells have been drilled, with further wells planned. Reservoir quality is extremely good with porosity around 36% and permeabilities in the range of 2–10 D. The field is produced via the Armada Kraken floating production storage and offloading vessel. Developed stock tank oil originally in place is in the region of 400 MMbbl, with further currently undeveloped resources to the west of the field.

The Mariner Field, Block 9/11a, UK North Sea

Abstract The Mariner Field is located on the East Shetland Platform in UK Block 9/11, 320 km to the NE of Aberdeen. The 9/11-1 well was drilled in 1981, discovering oil in the Paleocene Heimdal Sandstone Member and the Paleocene Maureen Formation. The deeper Maureen Formation was deposited on a submarine slope as canyon fill, and overspill canyon sands and debrites. The Heimdal Sandstone Member was deposited above the Maureen Formation on the same inherited, but younger, submarine slope system as deep-water slope channels, and is encased within suspension-deposited Lista Formation claystones. These slope channel sands have undergone post-depositional remobilization and sand-injection processes, leading to the complex sandstone geometries identified and mapped on seismic data. During a 36-year period, 28 exploration, appraisal and production test wells were drilled in UK Block 9/11, but only now is the field finally undergoing development. The long interval between discovery and development is due to several key issues, including the fact that development of heavy oil is technically and commercially challenging, and that the seismic imaging of the Heimdal Sandstone Member has been difficult or not possible until recently. These challenges are being overcome and the Mariner Field started producing in August 2019.

Relationship between bowl-shaped clastic injectites and parent sand depletion: implications for their scale-invariant morphology and composition

Abstract Three-dimensional seismic reflection data provide a means to assess the impact of injection on parent sands, and to quantify the character of the resulting injectite networks. The morphology of a series of large injectite structures hosted in the Paleocene Lower Lista Formation were mapped using broadband 3D seismic data from the North Sea to investigate their relationship with parent sands. Fourteen bowl-shaped structures were identified within the Lista Formation in the study area (60–85 m in height, and 200–900 m in width). Sand is absent (below resolution) below these large-scale bowls, suggesting that the parent sand is the underlying Maureen Formation and that sand ‘welds’ formed, rather than sand-prone channelized deposits within the Lista Formation. Identification of injectite networks can be ambiguous, which impacts geological model development. Observations from exhumed systems and core offer high-resolution insights into the complexity of injectite networks. To advance our understanding of this scale gap, we argue for injectites being scale invariant in their shape and grain size. This permits the application of outcrop-scale knowledge to seismic-scale interpretation. The demonstrable depletion of parent sands, and their scale invariance, can be applied to basin-fills worldwide to reduce uncertainties of the impact of sand injectites on hydrocarbon reservoirs.

New Paleocene species and biostratigraphic relevance of the genus Spiniferites across the North Sea and Norwegian Sea

Industrial palynological studies of the Paleocene of North Sea and Norwegian Sea basins over several decades have led to the consistent recognition of six distinctive species of organic-walled dinoflagellate cyst genus Spiniferites. These species, however, have not previously been formally described, a situation that we remedy herein. Hence, we propose the new species Spiniferites fentonii, Spiniferites rhomboideus, Spiniferites truncatus, Spiniferites sabulus, Spiniferites kirschii and Spiniferites dolichoidus. These new species have distinctive morphological features that separate them, from other species, both of Spiniferites and other genera. Some of the new species are very useful stratigraphic markers across north-western Europe. The material described is from the early Thanetian Lista Formation and a late Danian interval including the basal Maureen Formation and parts of the Våle Formation. The new species have not been observed in the Selandian (between the Danian and Thanetian), and Spiniferites diversity during that stage seems to have been lower in general across the study area; this was probably related to regional environmental changes. The stratigraphic range of the new species is used in combination with other known markers to increase stratigraphic resolution across the region.

Seismic and structural characterization of fluid escape pipes using 3D and partial stack seismic from the Loyal Field (Scotland, UK): A multiphase and repeated intrusive mechanism

The potential for fluid leakage from sub-surface reservoirs has important implications for CO2 storage, hydrocarbon reservoirs and water resources. Understanding the genesis, morphology, fluid flow mechanisms and extent of fluid escape from reservoirs allows for better risking of geological resources and storage potential. Here we describe in detail the structures of fluid escape pipes from the Loyal Field, observed from a 3D full and partial stack seismic dataset. The seismic imagery suggests that the fluid escape pipes are rooted at least in the main Paleocene reservoir and by-pass the reservoir seal to cross the post Lista Formation overburden up to the intra-Neogene units. The pipes extend for a few hundred meters to a few kilometres and show varying shape and structure from blow-out structures to incipient mud volcanoes. A detailed analysis of the seismic characteristics observed both from main baseline and partial stack data allows a division of the pipes into two families: (1) seeps and pipes following structural discontinuities and (2) pipes unrelated to the pre-existing structural features. The pipes internal seismic response, the reflector termination of the main conduits and the distribution of stacked bright reflectors suggest an upward migration mechanism (during pipe birth and development), requiring a cyclic switching from non-Darcy hydrofracturing (during overpressure) to Darcy flow lateral migration (during low-pressure stage).

Berthierine formation in reservoir rocks from the Siri oilfield (Danish North Sea) as result of fluid–rock interactions: Part I. Characterization

Berthierine as the only authigenic Fe-rich clay mineral occurs in an oil-bearing, glauconite-rich sandstone (Paleocene Heimdal Member of the Lista Formation, Danish North Sea). Based on the results of thin section, transmission and scanning electron microscopy, five different morphological types of berthierine were identified: (1) mainly as grain-coatings partly together with authigenic quartz covering detrital grains, (2) as pore-filling clay in open pores, (3) small crystals in transformed glauconite grains, (4) small crystals associated with siderite in layers of mica/micaceous glauconite, and (5) as elongated crystals in siderite concretions. Although different in occurrence, all berthierine types investigated by microprobe analysis are of similar chemical composition, suggesting similar precipitation conditions. Investigations by transmission electron microscopy reveal that fine berthierine crystals display straight parallel layers with a typical lattice fringe spacing of 0.7 nm, and that their occurrence is intimately connected to oil phases in pore space. Partly, berthierine textures resemble mineralized oil–water emulsions. Berthierine is more abundant in the oil leg than in the water leg, but occurs especially abundant at the oil–water contact. The coexistence of berthierine together with quartz overgrowth, but also its appearance in glauconite indicates that berthierine formed in situ and that it is a product of glauconite dissolution. Berthierine formation is coupled to the reduction of aqueous Fe3+ into Fe2+ derived from glauconite dissolution, and is related to fluid–rock interactions triggered by oil degradation which occurred in the oil-filled zone and at the oil–water contact. The biomarker parameters pristane/n-C17 and phytane/n-C18 indicate an increased extent of oil degradation at the oil–water contact. On the one hand, soluble oil degradation products (methane, carbon dioxide, and hydrogen) changed the hydrogeochemical conditions (such as pH, pe, alkalinity, etc.), and controlled dissolution of glauconite (and feldspar). On the other hand, the changed hydrogeochemical conditions led to berthierine and quartz precipitation in water-wet reservoir intervals.

An integrated subsurface analysis of clastic remobilization and injection; a case study from the Oligocene succession of the eastern North Sea

The North Sea giant sand injectite province (NSGSIP) is the global type area for large-scale sandstone intrusion complexes. Despite decades of research on the NSGSIP, this paper presents the first detailed case study in which all aspects of the intrusion process have been constrained, including fluid and sediment sources, injection timing and driving mechanisms. The study describes and analyses high-amplitude discordant amplitude anomalies within the Oligocene succession in the eastern North Sea, which are interpreted as large-scale brine-saturated sand injectites. Potential feeder conduits extending from the top of the Paleocene Lista Formation to the base of the injectites indicate that the source sand was located within the Lista Formation; possibly deposited in a distinct valley cut into the top of the Chalk Group. The geometry of the observed injectites ranges from a basal sill with wings to V-shaped and conical; their dimensions range from 300 to 3700 m in width and up to 150 m in height. In all cases, a significant deformation of the overburden is observed. The study area is located in the Ringkøbing-Fyn High area above the basement high separating two smaller Paleozoic half-grabens. During the Oligocene, rapid and significant differential loading occurred. We interpret that the injectites formed due to remobilization of the source sand facilitated by overpressure caused by differential loading combined with a possible influx of fluids from the deeper succession. The case study has with its assessment of the full injection system, implications for the understanding of subsurface remobilization processes and furthermore for oil and gas exploration in the eastern North Sea.

Characterizing the Paleocene turbidites of the North Sea: the Mey Sandstone Member, Lista Formation, UK Central Graben

This paper presents an integrated seismic, petrophysical and core facies study of the Mey Sandstone Member of the Central North Sea Lista Formation. Seismic mapping and attribute analysis reveal that the Mey Sandstone Member is composed of distinct axial and lateral routing systems. In turn, the axial system can be divided into coeval western and eastern fairways defined by the underlying graben topography in a similar manner to the overlying Sele Formation (Forties) sandstones. These trends are confirmed by petrophysical analysis, which also reveals that the lateral systems are not as important as previously proposed and that the cycles of the Mey Sandstone Member prograded over time before a late stage of backstepping. These variations can be related directly to published sea-level curves. Core analysis reveals that mean grain size is the main control on sandstone quality and that similar proximal (channelized) to distal (sheet-like) changes in sedimentological facies occur to those described in the Sele Formation. It is argued that these deposits cannot be described as simple basin floor fans due to the impact of topography on turbidite flow routing and the existence of multiple entry points of sediment into the basin.

Differentiation of Palaeogene sand by glauconitic and geochemical fingerprinting, Siri Canyon, Danish North Sea

The submarine Siri Canyon is NE–SW-oriented and located in the Danish North Sea (Fig. 1). It contains a number of oil reservoirs with glauconite-rich sand. The reservoirs of interest in the Nini oil field are the Late Paleocene Tyr Member of the Lista Formation and the Kolga Member of the Sele Formation (Schiøler et al. 2007), presumably of Early Eocene age. These members have previously been known as the Ty and Hermod members (Hamberg et al. 2005; Poulsen et al. 2007). The sand shows signs of injection, both in cores and in seismic data. The aim of this work is to chemically characterise and fingerprint the sand in order to reveal the origin of the sand found in three horizontal wells, which could have been injected from one or both of the Tyr and Kolga members. Core samples were collected from two vertical wells of known stratigraphy to make a basis of comparison, whereas samples of the cuttings were collected from the three horizontal wells with ages primarily corresponding to the Kolga Member. The purpose was moreover to evaluate whether cuttings samples can be used for fingerprinting as an alternative to core samples.

An old field in a new landscape: the renaissance of Donan

Abstract The Donan Field was discovered in 1987 by BP well 15/20a-4. Oil is reservoired in Paleocene Lower Balmoral Sandstones of the Lista Formation. First oil was achieved from Donan on 28 April 1992 via two crestal producers to the Single Well Oil Production System (SWOPS) vessel O.P.V. Seillean . Peak production rates of 15 mstb/day were achieved before high well watercuts caused a significant drop in gross rates. Further attempts at development proved unsuccessful at the time. No further infill attempts were made as the field continued to be produced until it reached its economic limit in 1997. The field had produced 15.3×10 6 stb. Subsequently, block 15/20a was awarded to a partnership led by Kerr–McGee (North Sea) UK Ltd (now Maersk Oil North Sea UK Limited) in 2002 as part of the twentieth licensing round. Drilling results whilst testing the prospectivity on the block led to a focus towards Donan redevelopment. A combination of Rock Physics modelling and AVO, calibrated by appraisal drilling, and the integration of high-resolution biostratigraphy, played a significant role in the successful first phase of the ‘Dumbarton Project’, consisting of five horizontal producers and one produced water reinjection well. ‘Second oil’ from Donan was achieved on 19 January 2007 to the Global Producer III FPSO. Early production performance was in line with expectations with the field producing 20×10 6 stb within the first two years. In 2008 and 2009 further phases of development drilling took place on Donan with 2009 also expected to deliver two development wells in the Lochranza Field, a smaller, structurally distinct field to the east of Donan.

Lithostratigraphy of the Palaeogene – Lower Neogene succession of the Danish North Sea

As a result of a lithological, sedimentological and biostratigraphic study of well sections from the Danish sector of the North Sea, including some recently drilled exploration wells on the Ringkøbing–Fyn High, the lithostratigraphic framework for the siliciclastic Palaeogene to Lower Neogene sediments of the Danish sector of the North Sea is revised. The sediment package from the top of the Chalk Group to the base of the Nordland Group is subdivided into seven formations containing eleven new members. The existing Våle, Lista, Sele, Fur, Balder, Horda and Lark Formations of previously published lithostratigraphic schemes are adequate for a subdivision of the Danish sector at formation level. Bor is a new sandstone member of the Våle Formation. The Lista Formation is subdivided into three new mudstone members: Vile, Ve and Bue, and three new sandstone members: Tyr, Idun and Rind. Kolga is a new sandstone member of the Sele Formation. Hefring is a new sandstone member of the Horda Formation. Freja and Dufa are two new sandstone members of the Lark Formation. Danish reference sections are established for the formations, and the descriptions of their lithology, biostratigraphy, age and palaeoenvironmental setting are updated.

Colophon, contents, abstract, introduction, geological setting, previous work and material and methods

As a result of a lithological, sedimentological and biostratigraphic study of well sections from the Danish sector of the North Sea, including some recently drilled exploration wells on the Ringkøbing–Fyn High, the lithostratigraphic framework for the siliciclastic Palaeogene to Lower Neogene sediments of the Danish sector of the North Sea is revised. The sediment package from the top of the Chalk Group to the base of the Nordland Group is subdivided into seven formations containing eleven new members. The existing Våle, Lista, Sele, Fur, Balder, Horda and Lark Formations of previously published lithostratigraphic schemes are adequate for a subdivision of the Danish sector at formation level. Bor is a new sandstone member of the Våle Formation. The Lista Formation is subdivided into three new mudstone members: Vile, Ve and Bue, and three new sandstone members: Tyr, Idun and Rind. Kolga is a new sandstone member of the Sele Formation. Hefring is a new sandstone member of the Horda Formation. Freja and Dufa are two new sandstone members of the Lark Formation. Danish reference sections are established for the formations, and the descriptions of their lithology, biostratigraphy, age and palaeoenvironmental setting are updated.

The MacCulloch Field: improving reservoir characterization through time-lapse analysis

The MacCulloch oil field lies in Block 15/24b in the UK Central North Sea. The field is produced using a floating production storage and offtake facility from two sub-sea centres and has been on production since 1997. The original geophysical mapping of the field was based on 3D seismic data acquired in 1993. In April 2002, a repeat 3D survey was acquired over the field with the aim of better understanding the depletion of the field using time-lapse seismic analysis. The MacCulloch Field reservoirs are turbidites of the Upper Balmoral Sandstone Unit in the Lista Formation of the Upper Paleocene, which are connected to a large aquifer in the underlying Lower Balmoral Sandstone Unit. Connection to such a large aquifer means that pressure support over field life has been very good (<100 psi drop over field life). This fact, coupled with the lack of a gas cap, means that for the time-lapse analysis any change should primarily be due to a substitution of water for oil. The MacCulloch Field reservoir is made up of five discrete turbidite sandstone-dominated sand bodies, which can be distinguished on the seismic data. Examination of the time-lapse response in these bodies shows that they have acted as a primary control on the depletion of the field. The individual bodies have been analysed using 3D visualization and interpretation techniques, and incorporated into the geological model with differing rock properties assigned to each. Within the reservoir simulation model, the assignment of directional permeabilities to these units and the placing of transmissibility barriers at their boundaries substantially improved the history match of the field, thereby enhancing our ability to predict future performance and identify possible infill drilling locations.

The Maureen Field, Block 16/29a, UK Central North Sea

abstract The Maureen field comprises the Maureen, Mary and Morag Accumulations, the reservoirs being Palaeocene Sandstones, Upper Jurassic sandstones and Permian dolomites respectively. The field lies about 10 km NNE of the Moira Palaeocene field. Maureen was discovered in 1973, came on-stream in 1983 and produced 217.4 MMBBL (from an estimated STOIIP of 397 MMBBL). The field ceased production in October 1999. It is trapped in a four-way dip closure over a salt dome and scaled by the overlying Lista Formation mudstones. The reservoir is up to 450 ft gross thickness, with core porosity from 18-28% and good sand connectivity. Morag was discovered in 1979. came on-stream in 1991 and produced 2.6 MMBBL before being shut-in in 1994. It produced from clean fractured dolomites in a stratigraphic trap. Mary was discovered and came on-stream in 1991. The initial well died after 1 year. A later well was put on-stream in 1997. Mary produced 2.83 MMBBL before final shut-in in June 1999. Reservoir quality is reasonable, but sand distribution is problematic. All the oils are sourced from the Kimmeridge Clay formation on the adjacent Maureen Shelf area.

Seismic reservoir prediction using Bayesian integration of rock physics and Markov random fields: A North Sea example

Quantitative interpretation of seismic data for reservoir rock and fluid properties commonly relies on deterministic rock physics relations and may often neglect statistical variability or spatial correlation. Geostatistical methods, on the other hand, take into account spatial dependence but results are often obtained without properly formalizing rock physics relations between seismic measurements and rock and fluid properties. This paper presents a strategy for integrating deterministic rock physics relations and spatial, statistical representations within a Bayesian framework. Data from the turbidite Glitne Field in the North Sea (Figure 1) provide an example for the approach. Because the reservoir is very heterogeneous, merging statistics with rock physics is particularly worthwhile to improve seismic reservoir prediction. Figure 1. The location of Glitne Field in the North Sea and the top Heimdal horizon as illustrated by reflection times. Available data are AVO seismic attributes, well observations, two-way seismic traveltimes, and cap-rock properties. The focus is on describing the spatial probability distribution of reservoir facies and fluid saturation along the seismic horizon representing the top Heimdal Formation (Figure 1), which is capped by Lista Formation at approximately 2000 m. Available data include AVO attributes (zero-offset reflectivity and AVO gradient) extracted from 3-D prestack seismic data and log-based analysis of facies and fluid saturation in four wells. Figure 2 shows zero-offset reflectivity (top, left) and AVO gradient (bottom, left) along the horizon (with the facies and fluid observations in the four wells indicated), a plot of zero-offset reflectivity versus AVO gradient (top, right), and a well log from the area (bottom, right). Two-way seismic traveltimes to the horizon of interest and cap-rock properties (density, P - and S -wave velocity) from well logs are also available (Figure 1). A 245 × 505 grid, each block being 12.5 × 12.5 m2, covers the domain of interest. This …

Paleogene tuffaceous intervals, Grane Field (Block 25⧸11), Norwegian North Sea: their depositional, petrographical, geochemical character and regional implications

Paleogene volcaniclastic rocks from four wells from the Grane Field (Block 25⧸11), Southern Viking Graben on the western flank of the Utsira High (North Sea), have been studied. The tuffaceous intervals consist of the volcanic phase 1 (58–57 Ma) in the Våle and Lista Formations, and the volcanic phase 2 (55–52 Ma) in the Sele and Balder Formations. Tuff beds of phase 1 are interpreted as having been redeposited by turbidity currents, whereas those of phase 2 reflect normal settling of fall-out pyroclastics in water. Two types of fragments occur, the most abundant being vesicular pyroclasts with irregular shape and dark, microlithic, partly vesicular granules, representing shallow submarine, Surtseyan-type eruptions. The other type of pyroclastic fragments are vitric shards, which originate by quenching granulation during subaqueous eruptions. The tuffaceous intervals have been subdivided into (1) identified pyroclastics based on textural interpretations, and (2) assumed pyroclastics based on geochemical interpretations. The majority of the samples are sub-alkaline basalts and basaltic andesites. The phase 1 tuffs evolved from basalts to rhyolites upwards in the Lista Formation, and phase 2 tuffs consist of sub-alkaline basalts and basaltic andesites of within-plate origin, similar to the contemporaneous Lower Basalts in East Greenland, the Rockall Trough and the Middle Series on Faroes, all linked to the opening of the North Atlantic Ocean.

Palynostratigraphy and depositional history of the Palaeocene Ormesby/Thanet depositional sequence set in southeastern England and its correlation with continental West Europe and the Lista Formation, North Sea

Analysis of palynofloras from eleven sections of the Late Palaeocene Thanet Sand and Ormesby Clay formations of southeastern England has enabled construction of a stratigraphy for a period of approximately 2 Myr, based upon eighteen palynofloral association sequences. This high-resolution stratigraphy has allowed the accurate recognition of the extent of depositional sequences in the region. Deposition of claystones was initiated in Norfolk after 58.5 Ma as a prograding series of five parasequences, with the onset of sedimentation in the majority of the southeastern England area resulting from a subsequent rise in relative sea level at around 58 Ma. Relative sea levels reached a maximum at 57.91 Ma, after which a period of condensed sedimentation ensued. This first maximum flooding surface initiated deposition in the far south of the area (Kent), and was succeeded by a distinct fall in relative sea level and subsequent retrogradation of sedimentary units. A major change in lithology and palynofloras is marked by the initiation of a further sequence at approximately 57.5 Ma, with a second maximum flooding surface occurring shortly afterwards, followed by prograding sedimentary units. The uppermost part of the Thanet Sand and Ormesby Clay formations is composed of two separate maximum flooding events, the uppermost of which is poorly preserved. The lack of any other depositional units between these events suggests the presence of a significant disconformity at this point. Comparison of the palynofloral association sequences and flooding events of southeastern England, with sections in Belgium, Denmark and with the Lista Formation in the North Sea, demonstrates a close affinity between these areas. The transgressive surface identified at the base of the Thanet Sand Formation in southeastern England is preserved as the shales immediately overlying the Balmoral tuffite of the Lista Formation, and as the base of the Orp Sands in Belgium and Holmehus Formation in Denmark. The subsequent record of relative sea level change in the south is mirrored in the Lista Formation, with the maximum flooding events being represented by shales and the intervening prograding sequences by siltstones and thick sands. This comparability of the record implies a similar regime of relative sea level change in the North Sea and southeastern England area throughout the deposition of the Lista/Ormesby/Thanet sediments, prior to the contrasting environments of Sele Formation-Lambeth Group sedimentation.

An integrated palynological-palynofacies approach to the zonation of the Paleogene in the Forties-Montrose Ridge area, central North Sea

Abstract A palynological and palynofacies study of late Paleocene and early Eocene sediments of the central North Sea has been undertaken using 467 core samples from 11 wells on the Forties-Montrose Ridge. Conventional dinoflagellate cyst (dinocyst) biostratigraphy gives poor precision within the narrow ( c. 2.5 million years) time interval studied. Furthermore, dinocysts are often present in only very low numbers and are frequently poorly preserved. An alternative local zonation scheme is proposed on the basis of downwell variations in quantitative palynofacies and palynomorph occurrence data, and on angiosperm pollen ratios. Integration of these three sets of data indicates a potential sevenfold subdivision of the mid-Sele Formation (S2) to upper Lista Formation (L3) interval in this area, with up to five divisions within the Forties Sandstone Member. This composite zonation scheme appears to work reasonably well for the studied wells, and preliminary comparisons with independent biostratigraphic data from two of our wells indicate a partial correlation with the dinocyst zones.