bluuebunny/crossref_metadata_2025 huggingface dataset:
Cretaceous and Tertiary basin development west of Ireland
Authors: SHANNON P. M. , MOORE J. G. , JACOB A. W. B. , MAKRIS J.
Published: April 2010

The Porcupine, Rockall and Hatton–Rockall basins lie on the continental seaboard west of Ireland. Up to 9 km of Cretaceous and Tertiary strata are preserved in the Porcupine Basin, in contrast to 2–3 km in the Rockall and Hatton–Rockall basins. Differences in seismic stratigraphic sequences through the region are attributed to an interplay between the developing North Atlantic Ocean, post-rift thermal subsidence and sea-level changes. Localized Ryazanian fault-controlled alluvial fan clastic rocks in the Porcupine Basin are succeeded by Valanginian to Barremian marine deposits. Sea-level lowstands in Albian and Paleocene–Eocene times, interpreted as rift and ridge-push effects respectively, resulted in delta and submarine fan progradation. Rapid thermal subsidence in Early Oligocene times led to marine deposits and to the onset of geostrophic currents. Miocene slumping triggered shale-dominant turbidite development, followed by tranquil deep marine sediments as subsidence outstripped sedimentation. The Cretaceous sequence in the Rockall Trough is thought to contain extensive igneous bodies overlain by an Upper Cretaceous muddy chalk sequence which is cut by abundant Tertiary sills and dykes. A number of shale-prone Upper Tertiary sequences occur. The Upper Cretaceous to Lower Tertiary succession is thin and frequently absent in the Hatton–Rockall Basin.
Relationships between basement faulting, salt withdrawal and Late Jurassic rifting, UK Central North Sea
Authors: ERRATT D.
Published: April 2010

Seismic data are presented to illustrate the variety of structures found at the margins of the Central Graben and intra-graben horsts. The complexity of these structures is due to the interplay of Late Cimmerian basement extension and older salt withdrawal structures within the Zechstein–Jurassic interval. Basement extension occurred in phases from the Permian to Late Jurassic. Salt withdrawal commenced in the Triassic and continued to the Cretaceous, resulting in a network of salt withdrawal synclines and areas of salt preservation, termed ‘pods’ and ‘interpods’, respectively. During Late Jurassic extension and rifting, the interaction of basement normal faults and the overlying Zechstein–Jurassic section resulted in structures which vary according to the precise location of the basement fault beneath a pod–interpod complex. Variation in the type and complexity of structuring along basin margins results from the highly variable nature and degree of salt withdrawal prior to Late Jurassic rifting. Complex graben margin structures frequently lend themselves to be interpreted as wrench faults, with different implications for structural and stratigraphic interpretations compared to salt withdrawal interpretations. Careful evaluation of structural style at graben margins therefore has important implications for both prospect mapping and regional structural models
Source rock permeability and petroleum expulsion efficiency: modelling examples from the Mahakam delta, the Williston Basin and the Paris Basin
Authors: BURRUS J. , OSADETZ K. , GAULIER J. M. , BROSSE E. , DOLIGEZ B. , CHOPPIN DE JANVRY G. , BARLIER J. , VISSER K.
Published: April 2010

Petroleum source rock expulsion efficiency classification based solely on geochemical characteristics can be misleading. Source rock permeability characteristics are also important, especially where petroleum expulsion occurs as a separate phase flow. Thermal and maturity history reconstructions and overpressure development, simulated with the TEMISPACK model of the Institut Français du Petrole (IFP) using two-phase (water, petroleum) Darcy flow, illustrates the importance and influence of bulk source rock permeability for expulsion efficiency. Poor dispersed type III Mahakam pelagic shales, rich marine type II Bakken shales and Paris Basin Lower Liassic source rocks, including both rich Lower Toarcian shales and underlying, less rich Hettangian–Lotharingian marls, illustrate how strongly expulsion efficiency is controlled by bulk rock permeability. Simulation of overpressures in Mahakam and Bakken shales requires very low bulk permeabilities, in the nD range. This is too low to allow significant expulsion. These rocks are inferred not to be hydraulically fractured, despite the overpressures, such that expulsion would not be assisted by this mechanism. Lack of overpressures and regional hydrodynamic models suggest that Paris Basin Lower Liassic sources are at least 10 to 100 times more permeable than Mahakam or Bakken sources. Improved permeabilities can be attributed possibly to tectonic fracturing. This facilitates expulsion both into overlying Dogger reservoirs and underlying Keuper reservoirs, consistent with inferred expulsion efficiencies and oil saturation profiles.
The chemical composition of North Sea formation waters: a review of their heterogeneity and potential applications
Authors: WARREN E. A. , SMALLEY P. C.
Published: April 2010

Significant variations in the salinity, chemical and stable isotopic composition of formation waters can be observed in the existing published data from the North Sea Basin. Variations occur at all scales, from intra-formational and within-field to basin-wide variations in water chemistry within and between formations. Clearly, the present-day North Sea Basin waters are highly heterogeneous. These variations have important implications. Various aspects of formation-water chemistry impact upon reserves estimates (
R
w
) and scale prediction (e.g. Ba, Sr, SO
4
), and also yield valuable information on the processes of water–rock interaction and diagenesis leading to modification of reservoir quality. However, present understanding of the processes causing the compositional heterogeneities is limited by the sparse coverage of the existing published data. Consequently, a new effort is being made to compile formation-water data for all fields in the greatest detail possible. Interim results from this compilation are reported.
Prediction of large-scale communication in the Smørbukk fields from strontium fingerprinting
Authors: STØLUM H-H. , SMALLEY P. C. , HANKEN N-M.
Published: April 2010

This paper discusses a new method which uses intra-field variability of formation water chemistry as a measure of degree of reservoir compartmentalization. If two reservoir units are in good flow communication, it is more likely that any water compositional variations that might have arisen would have homogenized by mixing processes (diffusion, dispersion, flow). On the other hand, a lack of flow communication is likely to inhibit water mixing and thus preserve variations in water compositions. Thus, whatever the
cause
of intra-field variations in water composition, two reservoir units that have a similar water chemistry are more likely to be in good flow communication than two units with different water compositions.

In this study the isotopic composition of strontium (
87
Sr/
86
Sr) dissolved in the formation water was used to monitor formation water compositional variability. This natural isotopic tracer is particularly useful as it can be measured simply from conventional core samples by extracting residual salts which have precipitated in the pore spaces as a result of formation water evaporation during storage.

The Smørbukk fields (Smørbukk North and Smørbukk South, Haltenbanken area, Norwegian Continental Shelf) comprise three Jurassic reservoir intervals, the Garn, Ile and Tilje formations. In Smørbukk North the main problems are vertical compartmentalization by areally extensive shales and lateral compartmentalization by extensive quartz cementation. In one well, residual salt analysis (RSA) shows that water
87
Sr/
86
Sr compositions are extremely homogeneous in each of the Tilje 1 and 2 reservoir zones, indicating good internal vertical communication. However, the Tilje 1 and 2 waters are significantly different from each other, indicating that the shale that separates Tilje 1 and 2 is an effective barrier to vertical communication. A similar relation is seen in a second well, suggesting that the shale barrier is indeed laterally extensive. In the second well, Tilje 1 RSA data are the same as the results for that zone in the first well, indicating excellent lateral communication between the two wells. In Tilje 2, however, there is a distinct between-well difference in formation water composition, indicating that lateral communication is poor in this zone.

In Smørbukk South, lateral connectivity is further complicated by faulting. Using RSA data from three wells it was possible to predict that:

the Garn has good internal vertical communication, but is laterally divided into two isolated areas, probably the result of a sealing fault;

the Ile forms three laterally isolated compartments;

the Tilje is subdivided vertically into three flow units that are interpreted to have poor communication with each other in two of the wells. Laterally, Tilje 1 and 2 form two flow compartments, probably due to faulting.
The Bruce Field
Authors: BECKLY A. , DODD C. , LOS A.
Published: April 2010

The Bruce Field is a giant gas condensate accumulation which lies on the western side of the Viking Graben at the northern end of the Beryl Embayment. Although discovered in 1974, the Annex B was not approved until 1990 by which time the field had been shown to extend across three exploration licence blocks (9/8a, 9/9b and 9/9a) and to be extremely complex. There are three main elements to the complexity: structure, reservoir distribution and hydrocarbon charge.

The major structural elements are the Western Flank (a rotated fault block) and the Eastern High with a central low between, the Central Panel; however, relatively poor seismic data quality makes detailed structural interpretation difficult. Each of these structural elements has a different hydrocarbon–water contact, with a proven range of nearly 500 m. The shallowest contact is found on the Eastern High and though the contact in the central low is nearly 350 m deeper, pressure data indicate that the gas leg is in communication with that in the Eastern High. The distribution of the main reservoir, the Middle Jurassic Beryl Group, and the magnitude of the unconformity that underlies it, appear to be controlled by earlier faults which are cross-cut by the present structure. The result of these complexities is that long hydrocarbon columns can be found in the structural lows, and thick reservoir successions can occur on the structural highs.
Hyde: a proposed field development in the Southern North Sea using horizontal wells
Authors: STEELE R. P. , ALLAN R. M. , ALLINSON G. J. , BOOTH A. J.
Published: April 2010

The Hyde Field was discovered in 1982. It is a small gas field with a poor quality Lower Leman Sandstone reservoir, close to existing facilities. It may be typical of many future developments in the Southern North Sea. A development plan prepared for the field in 1989 was withdrawn because of the unacceptable economic risk. Since then, a revised plan has been prepared. It is proposed to produce the gas through three near-horizontal wells drilled close to the crest of the structure. These wells will target reservoir zones of moderate permeability (
c.
5 mD) formed from the deposits of large aeolian bedforms.

The viability of the project was sensitive to the economics of the downside case. The risk was investigated by a statistical analysis of field performance. This involved assigning a range to each of the parameters controlling field GIIP and deliverability. These were then combined statistically to produce a probability distribution of economic performance which in turn was used in the project evaluation. Following this analysis, funds were obtained for the drilling of an appraisal well to test the major remaining uncertainty: the deliverability of a horizontal well. This well was completed on 20 February 1992. The planning, drilling, results and consequences are described below.
Geological aspects of horizontal drilling in chalks from the Danish sector of the North Sea
Authors: FINE S. , YUSAS M. R. , JØRGENSEN L. N.
Published: April 2010

Field development in the Danish chalk fields using horizontal wells has increased productivity in low-permeability reservoirs, maximized fracture intersection with the wellbore and optimized oil rim development.

Horizontal drilling requires extraordinary planning in order to achieve proper well placement. Unfortunately, the available data from logs, shows and field mapping does not always give consistent results and adjustments to the planned well trajectory must be made. A review from Mærsk Oil experience indicates that despite uncertainties related to such factors as structural dip, fluid levels and faults, objectives can nevertheless be satisfactorily attained.

Several techniques incorporating 3D seismic, pilot holes, wellsite biostratigraphy, wellsite geology and logging while drilling are utilized. They have proven crucial for recognizing and implementing rapid changes in the prognosed well trajectory where necessary. Our experience further emphasizes the absolute necessity of ongoing communication between qualified wellsite and office personnel during both the planning and operational phases of drilling a well.
Evolution of extensional styles at the southern termination of the Nordland Ridge, Mid-Norway: a response to variations in coupling above Triassic salt
Authors: PASCOE R. , HOOPER R. , STORHAUG K. , HARPER H.
Published: April 2010

The southern termination of the Nordland Ridge, mid-Norway exhibits variations in extensional style which can be attributed to differing degrees of coupling between pre-salt ‘basement’ and post-salt ‘cover’ strata. South of the Nordland Ridge, Jurassic and Cretaceous extension is distributed relatively uniformly over the 80 km wide Halten Terrace. Further to the north the zone of extension narrows to less than 40 km and the majority of the extension is taken up on the Revfallet Fault, which separates the Dønna Terrace from the Nordland Ridge. Displacement on the Revfallet Fault, at basement level, increases progressively from its zero displacement tip to a maximum of 7 km, 60 km to the north. At low displacements, extension in the cover is decoupled from the basement extension and vertical level changes are accommodated by monoclinal flexure. As displacement on the Revfallet Fault increases, the degree of basement-cover coupling increases and a much closer spatial link between deformation in the basement and in the cover is evident. This progressive increase in degree of coupling is characterized by increased footwall uplift and decreased extension in the cover away from the master fault. The degree of basement-cover coupling can also be shown to vary not only with displacement but also with time, in response to variable strain rates. Initial extension during the Jurassic was predominantly decoupled and occurred over 50 Ma period. After 40 50 Ma of relative quiescence, the major extensional episode occurred within a comparatively short 10 Ma period in the mid-Cretaceous. This later period of rapid extension requires strain rates at least an order of magnitude greater than those of the Jurassic. The results of this study have led to significant changes in the regional tectono-stratigraphic model.
The Zeta Structure: a footwall degradation complex formed by gravity sliding on the western margin of the Tampen Spur, Northern North Sea
Authors: BERGER M. , ROBERTS A. M.
Published: April 2010

The Zeta Structure (NOCS Block 34/4) is situated to the north of the Snorre Field, in the Tampen Spur area of the northern Viking Graben. The Zeta area shows a tectonic development and geometry markedly different from the typical fault blocks of the northern Viking Graben, which are most commonly asymmetric half-graben, with hydrocarbons trapped at the crest. The Zeta Structure is a ‘twisted’ horst block between two opposed major fault complexes. It occupies a ‘conjugate overlapping’ transfer zone. An east-dipping, rather flat fault in the Zeta Structure appears to be locally anomalous and is well imaged on 3D seismic data. This fault has been cored in Well 34/4–5 and defines the boundary between Lower Jurassic in the hanging wall and Triassic rocks in the footwall. The fault is remarkably clear on seismic data, and is seen to truncate the top of the older Inner Snorre Fault. The Jurassic section has in part been carried into the pre-existing hanging wall basin east of the Inner Snorre Fault, where it has been protected from Late Jurassic erosion. The Zeta Fault is interpreted to be a gravity slide, generated as a result of footwall uplift and gravity collapse adjacent to the Inner Snorre Fault. Those slide blocks, which have not been carried east into the hanging wall basin and remain on the Zeta Ridge, show a well-defined internal stratigraphy which can be mapped on seismic data.

Unusually, the Zeta gravity-slide is itself cut by younger, steeper faults, which dip to the west and comprise the western margin of the ‘twisted’ horst. Thus the fault zone at the eastern flank of the horst predates the gravity sliding, while the fault zone at the western flank post-dates the sliding. Forward modelling of the full syn-rift history predicts a total footwall uplift of
c.
1750 m at the crest of the Zeta Structure. The Zeta gravity-slide can still be located on seismic data where it has been faulted down to the west, towards the Marulk Basin, as also can an associated erosional (footwall) unconformity. Both the fault plane and the unconformity are buried by the Draupne Formation indicating that all tectonic activity occurred during the Late Jurassic (s.l.) and did not extend into the Cretaceous.
Middle Oxfardian to Volgian sequence stratigraphy of the Greater Shearwater area
Authors: JEREMIAH J. M. , NICHOLSON P. H.
Published: April 2010

A Middle Oxfordian to Volgian sequence stratigraphic model for the Greater Shearwater area is presented. This model builds on the genetic stratigraphic sequences of Partington
et al.
(1993
b
), refining the position of key stratigraphic surfaces with an additional emphasis on sequence boundary description. Most stratigraphic surfaces are believed to be related to tectonic events superimposed on a gradual rise in relative sea-level from the Middle Oxfordian to Volgian. Biostratigraphic information drawn from throughout the UK Central Graben allied with regional log correlation and seismic data has allowed a robust sequence stratigraphic framework to be developed which is applicable to the Greater Shearwater area.
The first deepwater well in Norway and its implications for the Upper Cretaceous Play, Vøring Basin
Authors: KITTILSEN J. E. , OLSEN R. R. , MARTEN R. F. , HANSEN E. K. , HOLLINGSWORTH R. R.
Published: April 2010

Well 6707/10-1 in the Nyk High licence PL218 was the first exploration well to be drilled in the deepwater Vøring Basin. It targetted a prominent tilted fault block trap with a pronounced flatspot conforming to structure. The pre-drill evaluation highlighted gas-over-water, with the gas–water contact (GWC) at the flatspot, as the most likely case. Given the water depth of 1274 m and the remote location of PL218 this case was not commercially attractive. However, seismic attributes indicated the possibility of an oil leg below the flatspot and this gave the necessary encouragement for drilling the well. The presence of an oil-prone source rock, and more importantly, its maturation relative to trap formation, were seen as the main pre-drill risks.

The well found an excellent quality Santonian to Early Campanian age reservoir of more than 1000 m thickness and a 156 m thick column of dry thermogenic gas. Poor oil shows were recorded on core chips and small amounts of heavier hydrocarbons were extracted from the core. This is seen as an important finding of the well, although the concern over the timing of maturation and migration relative to trap formation still remains.

Reservoir presence is considered low risk for future wells in areas where the distinct seismic character can be tied to the Nyk High well. The sandy nature of the Santonian to Lower Campanian section does, however, also mean that traps relying on fault seal (e.g. hanging wall traps) are high risk and that the possibility for stacked pools is reduced compared to the pre-drill view.

The flatspot does not match the current free-water level and is interpreted to represent an earlier, deeper gas–water contact. The reason why the contact moved up is not yet fully understood and may be a result of either late fault reactivations or gas compression during the Plio-Pleistocene burial. Late fault movement is a general concern in the Vøring Basin, with faults in some areas cutting up to seabed. If the contact moved up because of gas compression, it has the implication that gas charge to the trap, and Nyk High area, had ceased in the Plio-Pleistocene.
Evidence for pre-Cretaceous rifting in the Rockall Trough: an analysis using quantitative plate tectonic modelling
Authors: COLE J. E. , PEACHEY J.
Published: April 2010

Plate tectonic reconstructions of the North Atlantic Margin, west of Britain and Ireland have been generated using computer modelling software. A particular emphasis has been placed on the timing of rift phases within the Rockall Trough as this has significant implications for the distribution of Mesozoic hydrocarbon source rocks. A variety of geophysical and bathymetric data have been integrated to update existing plate boundary definitions, which has improved the resolution of the modelling. Forward and reverse modelling studies were then employed to quantify the amount of rifting in the Rockall Trough. Present-day plate outlines were contracted to discover the amount of intra-plate deformation required for a geometric fit. These results were then compared with the effects of contracting plate outlines by specified amounts usingβfactors from independent datasets from the Rockall Trough and adjacent areas.

The reconstructions suggest that the majority of rifting occurred in the mid to Late Cretaceous and continued into the Eocene. They also indicate the occurrence of at least one episode of pre-Cretaceous rifting corresponding to a β factor of 1.6. The results of this study are corroborated by an independent structural and stratigraphic basin modelling project that examined the crustal evolution of the Rockall Trough. This produced a range of model solutions which, when constrained by data from this study and elsewhere, suggests a best-fit solution which requires a substantially thinned pre-rift crust, best explained by a pre-Cretaceous basin. The implications of the presence of an older rift system are favourable for hydrocarbon exploration in the area. Regionally there are important petroliferous Triassic to Jurassic rift systems and it is likely that an older rift system in the Rockall Trough would be of a similar age with significant potential to be hydrocarbon bearing.
Structural evolution of the Slyne Trough
Authors: DANCER P. N. , ALGAR S. T. , WILSON I. R.
Published: April 2010

The Slyne Trough is a Mesozoic half-graben which lies approximately 60 km offshore west of Ireland, in water depths of 200–400 m. It is part of a Mesozoic basin system which stretches from the West of Shetland basins in the north to the Porcupine Basin in the south. The Slyne Trough can be divided into three asymmetric half-graben, containing a thick section of Permo-Triassic and Jurassic sediments, which are unconformably overlain by a thin Tertiary/Quaternary section. This subdivision of the basin is controlled by the presence of a number of complex transfer zones which show strike-slip movement and post-Miocene reactivation, and are often characterized by zones of poor quality seismic data.

The major rifting episode in the Slyne Trough occurred during the Middle Jurassic. Up to 2.5 km of Aalenian to Bathonian sediments are preserved in a number of NNE–SSW trending half-graben sub-basins. These reverse their dip directions (polarity) from east to west at transfer zones, which cut across the Slyne Trough. This main rifting episode is interpreted to have been linked to the proto-North Atlantic rifting process, the episodes of rifting being related to the relative motion of the Rockall Plateau with respect to Eurasia.
The thermal impact of Paleocene magmatic underplating in the Faeroe–Shetland–Rockall region
Authors: CLIFT P. D.
Published: April 2010

Voluminous magmatism on the northwest European shelf during Palaeogene continental breakup is believed to result in crustal thickening by gabbroic accretion to the base of the crust totalling 4–5 km west of Scotland, 5–8 km around the Faeroe Islands, but only 1–2 km beneath much of the Faeroe Shetland Basin. Simple models of heat conduction predict high heat-flow (>120 mW m
−2
) following underplating of 5 km of gabbro. This is, however, not substantiated by thermal modelling derived from vitrinite reflectance and apatite fission track data from wells in the Rockall Trough, which show peak heat-flow of <70mWm
−2
in the central Rockall Trough and 55–78 mW m
−2
in the Faeroe–Shetland Basin. Present day values are 45 mW m
−2
and 55–63 mW m
−2
, respectively. The additional heat-flow is about 60% of that predicted by conduction models assuming instantaneous underplating of a single body. Underplating appears to have taken place progressively over ≈11 Ma (51–62 Ma) in the form of small plutons, thus reducing the thermal impact compared to an instantaneous event. Nonetheless, variability in underplating is the dominant influence on regional heat-flow and may have had a major impact on source-rock maturation. The oil generating window is predicted to have shallowed by ≈1.4 km in the northern Rockall Trough in the early Eocene. Present day heat-flow readings indicate that the background heat-flow against which the underplating peak is superimposed increases from 45 mW m
−2
in the southern Rockall region, to 50 mW m
−2
in the northern Rockall, and reaches 55–60 mW m
−2
in the Faeroe–Shetland Basin. This pattern must reflect changes in the radiogenic content of the underlying crystalline basement and/or its thickness, as most of the underplating-derived heat has now dissipated.
The Turonian play in the Faeroe–Shetland Basin
Authors: GRANT N. , BOUMA A. , McINTYRE A.
Published: April 2010

Recent exploration in the Faeroe–Shetland Basin has concentrated on the Paleocene, following the successes of the Foinaven and Schiehallion fields. However, a number of deeper Mesozoic plays may still exist in the basin. This paper describes results of recent exploration activity targeted at a Turonian play in the Faeroe–Shetland Basin, west of the Rona Ridge, and discusses implications for future prospectivity in the area. The play tested is a slope fan pinchout against the Rona Ridge, comprising Cenomanian–Turonian high density turbidite sandstones. These were shed into a deep-water basin in the hanging wall of the Rona Fault during a base-level change in the adjacent West Shetland Basin. Two wells have proven considerable thicknesses of interbedded sandstones and shales in the Cenomanian–Turonian interval. Reservoir quality is locally excellent with porosities exceeding 20% and permeabilities up to 1 D. While hydrocarbon shows have been encountered, targeted prospects appear to have failed because of a lack of up-dip seal, emphasizing that the key risk for down-thrown plays against the Rona Fault remains trap integrity. The presence of both oil and gas shows though, confirms that the Turonian sandstone package has acted as a migration focus and may represent the main conduit from the deeper Jurassic source kitchen into the Clair Field. A sedimentological and diagenetic model for the sandstones based on recently acquired core data implies that clean, high quality deposits may also exist in a more basinward setting, possibly as detached fan complexes. This stratigraphic interval remains a potential play for future exploration, but with the depth of burial increasing rapidly westwards, overpressuring may be required to preserve porosity and permeability.
’NW European Gas Atlas’ – new implications for the Carboniferous gas plays in the western part of the Southern Permian Basin
Authors: GERLING P. , GELUK M. C. , KOCKEL F. , LOKHORST A. , LOTT G. K. , NICHOLSON R. A.
Published: April 2010

The ‘Northwest European Gas Atlas’ comprises maps on characteristics (e.g. molecular and isotopic compositions) of natural gases in northwest European gas fields, on the distribution and facies of source and reservoir rocks, on maturities, and other relevant geological information. The mapped area includes the entire Southern Permian Basin from the Southern North Sea to central Poland. Palaeozoic source rocks in the Dinantian, Namurian and Westphalian have been identified in the western part of the Southern Permian Basin. They contain kerogens of marine (Type I and II) and continental origin with TOC contents as high as 12%.

There are two Carboniferous production provinces in this area: C1 in the Southern North Sea and C2 in the area along the border between The Netherlands and Germany. The natural gas in most of the C1 production province has methane contents of more than 80%; in most of the C2 province even more than 85%. Nitrogen is the second most abundant constituent in both provinces. Carbon dioxide plays a significant role only locally in the areas of intrusive rocks. Isotope data show that the source of the natural gases in the C2 province is a terrestrial rock (Westphalian). In the C1 province, the gases are of mixed origin: a low maturity terrestrial source rock (Westphalian) and a more mature marine source rock (?Namurian).
Sequence stratigraphy and sedimentary history of the Humber Group (Late Jurassic-Ryazanian) in the Outer Moray Firth (UKCS, North Sea)
Authors: KADOLSKY D. , JOHANSEN S. J. , DUXBURY S.
Published: April 2010

The Humber Group in the Outer Moray Firth is an onlapping sedimentary succession of Late Oxfordian to Ryazanian age, recording a trend of continuously rising relative sea-level. Nineteen subordinate transgressive–regressive cycles (‘sequences’) have been identified in the numerous wells in the area. The identification of these sedimentary units throughout the study area is indispensable for the interpretation of its sedimentary history, and hence for the ability to predict the possibility of subtle stratigraphic traps. Transgression began during the Late Oxfordian in the North Buchan Graben and culminated in the Early Ryazanian, when only parts of the Halibut Horst and the Fladen Ground Spur remained exposed. Mapping of the onlap reveals the drowning from the south of a significant topographic relief, which was further enhanced by syndepositional rifting. Three structural grains affected sedimentation: (1) E–W (possibly a repeated reactivation of pre-Late Jurassic faults, e.g. North Halibut Graben: pre-Late Oxfordian to Middle Volgian); (2) NE–SW (e.g. Theta Graben: Late Oxfordian to Early Kimmeridgian; Highlander–Piper Ridge: Kimmeridgian to Mid-Volgian); (3) NW–SE (e.g. Witch Ground Graben: Early Volgian to Ryazanian). Sedimentation was initially dominated by coastal plain and shoreface facies of marine-dominated deltas and estuaries (Piper Formation
s.l.
), sourced mainly from the Fladen Ground Spur. From deposition of the upper Piper Formation onwards, intra-rift horsts, particularly the Halibut Horst, were also important sand sources. Deltaic systems back-stepped toward the basin flanks when accommodation space generation began to exceed sediment supply. Increased rifting in Early Volgian times triggered large-scale mass flow deposition from the Halibut Horst and from the East Piper High. Back-stepping shoreface systems continued their progressive onlap of the basin margins. Lowstand systems tracts in the individual sequences were muted by the overpowering long-term transgression, and significant mass flow deposits were not primarily controlled by the collapse of constructional highstand shelf margins. Instead, long-term tectonic uplift of specific areas sourced basin-margin submarine fan systems, typically confined to half graben on the flanks of the basin (e.g. Claymore sands), and basin-floor submarine channel systems in the core of the Witch Ground Graben (e.g. Galley sands). The potential for subtle stratigraphic traps is greatest in these turbiditic sandbodies where their boundaries are abrupt, as a result of channeling in self-constructed levees, or confinement by fault-induced seafloor topography.
Chalk exploration, the search for a subtle trap
Authors: BRAMWELL N. P. , CAILLET G. , MECIANI L. , JUDGE N. , GREEN M. , ADAM P.
Published: April 2010

Over 2 × 10
9
STB of oil and 8.9 × 10
12
SCF of gas have been produced from the chalk fields of the Greater Ekofisk area, more than 50% of that being produced from the giant Ekofisk Field. Phillips Petroleum Company Norway and the PL018 licence co-venturers have undertaken a comprehensive and integrated re-evaluation of the chalk exploration potential in Blocks 2/4 and 2/7 of the Norwegian Continental Shelf. Recent exploration models indicated the potential for significant untested reserves to exist in the chalk of Blocks 2/4 and 2/7. The Chalk Exploration Project (CEP) team was given the objective ‘to define the risked value of the remaining chalk exploration potential in licence PL018’. All major structures and significant amplitude anomalies at chalk level had been drilled by 1986, leaving only the subtle field flank and stratigraphic plays for evaluation. Although many studies had been completed in the chalk over the years since discovery of Ekofisk Field in 1969, most of these studies had been focused on a single field and no regionally consistent stratigraphic framework or depositional model had been developed. As part of this project, a robust regional model for chalk prospectivity was developed covering the whole chalk basin, based on a sequence stratigraphic analysis of regional seismic and well databases, together with petrophysical, hydrodynamic, geochemical and other key technical studies. Acquisition of 3D seismic data over the chalk fields since the mid 1980s demonstrated the power of 3D seismic analysis to define stratigraphic detail within the chalk, and by 1993 the entire licensed area of Blocks 2/4 and 2/7 was covered by 3D data, giving the opportunity to undertake a semi-regional, sequence stratigraphic 3D analysis of the chalk reservoir in PL018, and determine the remaining exploration potential.
Ekofisk Field redevelopment: improved reservoir management through cross-discipline technology and integration of three dimensional models
Authors: KEY S. C. , AGARWAL B. , SØILAND G. V. , NIELSEN H. H.
Published: April 2010

The Ekofisk Field is currently undergoing a major field re-development in which 45 new wells will be drilled before the end of 1998. This requires that the most comprehensive and detailed reservoir description and geological and fluid flow models be used as the basis for the planning of such a redevelopment. This situation, as well as new developments in hardware and software and multidisciplinary database and applications integration, led to the decision in 1994 to completely re-evaluate the reservoir characterization of the field. A major multi-disciplinary effort involving geoscience, petrophysical and reservoir engineering work was initiated through the Ekofisk reservoir characterization (ERC) project. The objective of the reservoir characterization project was to improve the existing reservoir description using all available data through the application of new techniques and technology, and to construct and history match a new 3D reservoir fluid flow model using this updated, detailed reservoir description. Greater demands are being made on geoscientists and engineers to model and manage processes taking place within the reservoir. At the same time systems are evolving which allow large and complex models to be developed and modeled in simulators. The development of these models, and asset management based on these models, are becoming requirements for effective reservoir management. Our biggest challenge is to maintain, update and interchange data between the large 3D reservoir description models and fluid flow models through integration of new data. Up-scaling of the detailed description produced the highest resolution model that is computationally manageable. The resulting history-matched fluid flow model provides the primary reservoir management tool for the field re-development programme and for the evaluation of reservoir and geoscience monitoring technologies. Down-scaled reservoir parameters are currently being integrated with petrophysical data and laboratory core analysis to drive seismic forward modelling of present and future reservoir conditions. These seismic simulations are being used to evaluate the implementation of a time-lapse seismic (4D) monitoring programme for the field.
Capturing reservoir heterogeneity in a sand-rich submarine fan, Miller Field
Authors: GARLAND C. R. , HAUGHTON P. , KING R. F. , MOULDS T. P.
Published: April 2010

Miller production began its decline phase in July 1997. To investigate the challenges of the decline period and the options for extending field life a detailed reservoir heterogeneity model was set up based on analysis of 26 wells, of which 19 were cored. The Miller fan is a high net: gross sandy submarine fan system in which lobe abandonment facies and numerous thin shales form the important heterogeneities. Each reservoir zone was described in terms of eight depositional elements and fourteen lithotypes. These descriptions were incorporated into the model at a resolution which ensured capture of the most significant heterogeneities. A stochastic generator was used to build a detailed static description of the permeability of the reservoir. The important heterogeneities were captured in a cell size of 60 m × 60 m ×
c.
0.02 m. Volumetric rock properties such as zone isochore, net: gross and porosity were mapped using conventional methods. The static description was up-scaled into an area of local grid refinement of the Eclipse reservoir simulator with 33 dynamic subzones at a cell size of 100 m × 100 m ×
c.
2.5 m. The detailed reservoir model matched well and field performance in the decline period more closely than the previous deterministic model. Stochastic realizations of the model enabled a better estimate of uncertainty to be demonstrated. The success of the process indicated that greater benefit would be obtained by its extension over a larger area of the field.
Predicting sandbody distribution and porosity for Callovian to late Oxfordian succession; Block 9/13 UKCS: an integrated approach
Authors: WOOD M. , BINGHAM G. , MITCHELL P.
Published: April 2010

Middle to Upper Jurassic clastic deposits of the Block 9/13 area show an evolution in their sedimentary characteristics and depositional style, which are attributable to the interplay between rising relative sea-level, decreasing sediment supply and the development of an extensional fault framework. An understanding of the temporal and spatial relationship between fault activity and sediment supply is critical in determining reservoir distribution. Four evolutionary stages are identified: (a) Bajocian–Bathonian fluvio–tidal deposits: sedimentation occurred in a simple N–S trending extensional system, comprising discrete fault segments, coupled with high rates of sedimentation with a southerly provenance. (b) Callovian–Oxfordian submarine channel to pro-delta deposits: axially transported sediments are deposited in hanging wall lows of N–S orientated fault segments. Sediment supply is outstripped by the creation of accommodation space. (c) Mid–late Oxfordian submarine gravity flow deposits: axially transported sediments were deposited in closed synclinal lows created by the intersection of N–S and NW–SE, SW–NE fault trends, resulting from ramp-relay collapse. (d) Kimmeridgian–Volgian debris flow deposits derived from the footwalls of uplifted fault blocks.

A case study is presented, integrating post-stack seismic inversion with more conventional datasets, to provide increased confidence in the Callovian–late Oxfordian geological model. The gross stratigraphic package between the Callovian and late Oxfordian is easily distinguished using conventional seismic data. However, with conventionally processed seismic data individual sandbody distribution and geometry is difficult to determine because of a combination of non-unique seismic responses at sand–shale interfaces and resolution limitations. Recent success has been achieved using post-stack seismic inversion of a wavelet-processed volume, to distinguish sand within a particular porosity range from all other lithologies, to an acceptable level of confidence.
Hydrocarbon systems modelling of the Norwegian Central Graben fairway trend
Authors: TAYLOR M. S. G. , LeROY A. , FØRLAND M.
Published: April 2010

The known hydrocarbon accumulations in the Norwegian Central Graben Fairway trend are forward modelled in this study. Particular attention is paid to the petroleum phase in the reservoirs as commercial and economic models of Central Graben prospects are closely linked to hydrocarbon type, especially in the less explored downdip areas.

Detailed seismic structure grids and well data are utilized in Finesse, an integrated 2D horizontal plane modelling program to simulate the maturation of source rocks and the expulsion, migration, and entrapment of generated hydrocarbons through time. All known Jurassic, Cretaceous, and Paleocene fields and discoveries were used to calibrate the model.

The study focused on migration through multiple layers defining vertical conduits between layers based on modelling seal capacity failure and fracturing rather than using faults as conduits. The maturity indicator used was the total transformation ratio (TTR) (the sum of the oil and oil to gas cracking transformation ratios) rather than vitrinite reflectance (R
0
). TTR is an accurate reflection of the state of source maturity whereas Ro is an indication of the thermal stress applied to the source.

The results show that 2D horizontal plane models can be used to predict known hydrocarbon accumulations over large regions and highlight areas of future prospectivity. This allows the explorationist to effectively focus on specific areas where more detailed 2D or 3D modelling can be applied.
The Jurassic petroleum system of the West of Britain Atlantic margin – an integration of tectonics, geochemistry and basin modelling
Authors: HOLMES A. J. , GRIFFITH C. E. , SCOTCHMAN I. C.
Published: April 2010

A re-appraisal of the Mesozoic and Cenozoic evolution of the Atlantic margin basins has been integrated with new data on source-rock kinetics, oil-source geochemistry and fluid inclusion studies to calibrate the petroleum systems of the study area and model these systems utilizing 2D modelling software.

The high β factors that are reported from these basins are cumulative estimates. Superposition of rifting events and evidence of prolonged rifting until the early Paleocene demonstrate that heat flow patterns associated with a ‘cool’ rift model are most appropriate.

New kinetic models for ‘Kimmeridge Clay’ and Middle Jurassic source-rock samples from released wells and BGS shallow boreholes allow more precise maturation modelling. Prolific oil-prone, Type I and Type I/II Middle Jurassic source rocks, together with fast-reacting Type IIS Upper Jurassic–Lower Cretaceous source rocks have been identified and indicate the range of kinetic models that must be considered during sensitivity analysis.

In the Faeroe–Shetland area, complex mixing of both ‘fresh’ and biodegraded oils from different source rocks as well as different facies of the same source-rock formation are recognized. Gas chromatography–mass spectrometry (GC–MS) and compound specific isotope analysis (CSIA) of oil samples and petroleum fluid inclusions are used to differentiate between oil families and also to separate oils within a sample.

A number of regional seismic sections were utilized for 2D modelling which was calibrated from well or pseudo-well models and incorporated new heat flow and kinetic data. These results and regional mapping indicate that the respective location of Lower Tertiary versus Upper Cretaceous depocentres is critical in determining the timing of maturation. Peak oil maturation occurs from mid Cretaceous to the present-day. Migration pathways initially focus hydrocarbons to Mesozoic (or older) highs. Early Tertiary faulting, mid Tertiary uplift and gas flushing then control re-distribution of hydrocarbons.
Jotun Field reservoir geology and development strategy: pioneering play knowledge, multidisciplinary teams and partner co-operation – key to discovery and successful development
Authors: BERGSLIEN D. , KYLLINGSTAD G. , SOLBERG A. , FERGUSON I. J. , PEPPER C. F.
Published: April 2010

Accumulated knowledge from the early pioneering wells and subsequent exploration history led to the discovery of several fields in the Utsira High area during the 1990s. One of these, the Jotun Field, was discovered in 1994. The Jotun Field consists of three structures and is located on the western flank of the Utsira High, close to the eastern pinchout of the Tertiary submarine fan system. The reservoir at Jotun comprises Paleocene Heimdal Formation sands shed from the East Shetland Platform and transported across the Viking Graben area onto the Utsira High by high density gravity flow processes dominated by sandy turbidites. These distal gravity flow deposits display both thin-bedded sands alternating with shales and thicker, more massive sandstones (tens of metres thick). Minor sand injections occur throughout the field but are volumetrically insignificant. The production wells in one of the structures are completed in a slump and injection complex above thick massive reservoir sands. The Jotun Field development strategy was designed to optimize oil capture and minimize risk based on the interpreted reservoir geology. The initial development comprised 14 development wells: 12 horizontal producers, 1 water injector and 1 water disposal well. Production from the Jotun Field started in October 1999 and reached peak production in June 2000, with 140 000 BOPD. After exceeding initial expectations, declining production and rising water cut prompted an infill well programme, time-lapse seismic data acquisition and production logging in 2002. The first two wells were disappointing due to facies transition to interbedded sands and shales on the flanks of the structure and underprediction of oil–water contact movement. The newly available time-lapse seismic data were then integrated with production logging and updated depositional facies studies to evaluate additional drilling opportunities. The discovery, appraisal and development history of the Jotun Field serves as a good example of the key challenges in the Tertiary Utsira High play and the strength of applying multidisciplinary team efforts, partner co-operation and involvement to optimize asset value through tailored drilling and data acquisition programmes.