bluuebunny/crossref_metadata_2025 huggingface dataset:
Tullich Field
Authors: RODRIGUEZ J. M. , SCHOLEY H. , FLANAGAN K. P.
Published: April 2010

Tullich Field, operated by Kerr-McGee Oil (UK) plc with 100% interest, lies in UK block 9/23a, to the southeast of Gryphon, and to the east of the Harding fields. The field is a subsea tie-back from a central manifold to the Gryphon ‘A’ FPSO (floating production, storage and offloading) facility. The southern part of the field was discovered by Hamilton in 1991–1992. Well 9/23a-27 and its sidetrack encountered thin oil and gas bearing sandstones of Lower Eocene age from the Balder Formation, which tested 570 bpd of 25.8 degree API oil. Kerr-McGee recorded a 3D seismic survey over the area in 1990, and in 1999 acquired a 3D OBC seismic survey over the Gryphon Field and the northern part of block 9/23a. The similarity of the inverted shear wave seismic data over the Gryphon Field and the northern part of block 9/23a was the catalyst for the further exploration and appraisal of the area. This led to an exploration drilling programme in 2001, which included the acquisition of full waveform shear sonic data and core. In July 2001, a separate discovery was made by Kerr-McGee with the drilling of 9/23a-29A, to the north of the 9/23a–27 wells. Thick oil bearing sandstones of excellent reservoir quality were encountered in the Balder Formation. The field was delineated between July and December 2001 by sidetracking 9/23a–29A and drilling the 9/23a–31 well. From a windowed extraction of peak amplitudes of the shear seismic data, it was noted that at Gryphon the high amplitudes corresponded to the presence of thick reservoir sandstones, whilst at Tullich it appeared that the high amplitudes related to a non-reservoir argillaceous sandstone sequence rather than the much thinner reservoir sandstones. These reservoir sandstones lie at different stratigraphic levels in the B2 unit of the Balder Formation but appear to be sufficiently in communication to act as a single reservoir unit. They are currently interpreted as sandstones deposited by turbidity currents which pinch out against the plunging nose of the Crawford Ridge. In order to take advantage of synergy with other work in the Gryphon area, a tight timeframe was imposed on the project. A four-well development drilling programme began immediately once the Department of Trade and Industry had given their approval of the Field Development Plan (FDP) in March 2002 and was completed by October 2002, with first oil achieved at the end of August 2002.
Tilted oil–water contacts: modelling the effects of aquifer heterogeneity
Authors: DENNIS H. , BERGMO P. , HOLT T.
Published: April 2010

In the North Sea tilted oil–water contacts (OWCs) are recognized in fields of Paleocene, Cretaceous and Jurassic age. In areas where lateral pressure (potentiometric) gradients exist in the aquifer, OWCs dip in the direction of pressure drop and hydrodynamic flow occurs. The direction and magnitude of potentiometric gradients in the North Sea vary locally, but are generally observed to be associated with de-watering of the overpressured Central Graben. Local variations in the potentiometric gradient can be caused by heterogeneity in the aquifer, such as faults, channels, facies changes, pinchouts and/or thinning. These variations cause local irregularities in a field’s tilted OWC. Where an aquifer beneath a field becomes less permeable or thins, the dip of the OWC increases. Where the aquifer becomes more permeable or thickens, then the tilted OWC tends to flatten out. Channels and high-permeability zones tend to concentrate aquifer flow and direct the potentiometric gradient along their axes. Various combinations of aquifer heterogeneity have been modelled in 3D simulations. These models are described and compared with real examples from North Sea fields.
Reserve growth in chalk fields of the North Sea
Authors: GAUTIER D. L. , KLETT T. R.
Published: April 2010

Reserve growth is the net increase in estimated recoverable resources of an oil or gas field or group of fields through time. This phenomenon is important in North Sea oil fields and is observed in all classes of reservoirs and in all country sectors. Oil fields with chalk reservoirs have exhibited particularly large increases in estimated recoverable reserves. Whereas chalk reservoirs contain only about 16% of recoverable North Sea oil, almost one third of the growth of reserves in existing fields has been in fields with chalk reservoirs. More than 60% of the currently reported recoverable oil (cumulative production plus remaining reserves) in chalk fields is attributed to reserve growth since 1985. In contrast, only about 34% of recoverable oil in all North Sea fields (chalk and clastic reservoirs) is from reserve growth. The large increase in estimated recoverable resources in the chalk reservoir fields of the North Sea results from both increases in estimated original oil in place and from improvements in recovery efficiency. Although the largest fields generally display the greatest volumetric additions to reserves, on a percentage basis reserves in small fields increase as much as reserves in larger fields. So far, growth of reserves in the chalk fields has been directly proportional to development effort, as indicated by numbers of wells drilled for delineation, development and improved recovery (including injector and observation wells). In spite of great improvements in understanding chalk reservoirs, estimates of original oil in place are still uncertain and overall recovery factors remain relatively low. Therefore, opportunity remains for further large additions to reserves in chalk reservoir fields. The experience of operators of the North Sea chalk fields indicates that large, complex accumulations with difficult reservoir engineering problems may present possibilities for additional oil recovery in such fields elsewhere.
The Valdemar Field, Danish Central Graben: field compartmentalization and regional prospectivity of the Lower Cretaceous chalk play
Authors: JAKOBSEN F. , INESON J. R. , KRISTENSEN L. , NYTOFT H. P. , STEMMERIK L.
Published: April 2010

Despite representing a widespread play in the Central North Sea, production from Lower Cretaceous chalks is currently confined to the Valdemar Field in the Danish Central Graben. The field comprises a heterogeneous reservoir succession, less than 100m thick, consisting of hemipelagic chalks, marly chalks, and marlstones of Late Hauterivian–Early Aptian age. Although the field has in-place reserves in the order of 115 × 10
6
m
3
(725 × 10
6
BBL), the recovery from this complex reservoir was initially estimated to be only approximately 1%, primarily due to low permeability. The argillaceous chalks of the Lower Cretaceous reservoir are highly faulted and fractured, overpressured and undercompacted, giving rise to a complex distribution of hydrocarbons. Due to the lithological heterogeneity of the succession, internal stratigraphic barriers are common and result in stratigraphic compartmentalization. In addition, clay smearing in fault zones has created structural barriers and the development of structural compartments, as reflected by spatial differences in oil saturations, oil types and maturity, formation pressure and porosity distribution. Analysis of the reservoir properties and structural development of the Valdemar Field has provided data that can be extrapolated to the remainder of the Danish Central Graben, indicating that the Lower Cretaceous is most prospective in the central and southern Danish Central Graben.
The Lower Cretaceous plays of the Central and Northern North Sea: Atlantean drainage models and enhanced hydrocarbon potential
Authors: OAKMAN C. D.
Published: April 2010

In the Central North Sea, the Apto-Albian play appears to be confined to patchy areas within the Moray Firth basins. In this area, it is widely believed reservoir-quality sands were sourced from local residual Late Cimmerian highs, with resultant limited distributions of commercial fairways. Local hydrocarbon modelling proves that most hydrocarbons discovered to date occur within stratigraphic traps, discovered largely by serendipity during appraisal of older structurally defined reservoirs. Re-appraisal of Jurassic to Cretaceous tectonic models shows how tectonic trends within the Moray Firth basins are optimized for discovery of Lower Cretaceous reserves. These models also suggest considerable upside potential in under-explored areas of the Viking Graben and Central Trough, where complex basin geometries and halokinesis conspire to hide potential fairways. The search for Aptian reserves is severely hampered by a widespread inability to see or interpret sand and/or hydrocarbon presence using seismic data alone, resulting in a very high dependence on geological modelling to evaluate potential sweet spots within wide fairway tracts. This style of modelling has been reliant on a ‘Jurassic-upwards’ technique, with limited success. Recent re-modelling of the entire North-West European area has shown that established models of Paleocene sand distribution can be projected downwards to find sweet spots in potential Aptian fairways. Using this approach has resulted in a new plate-wide tectono-sedimentological and drainage pattern model for the Aptian, which suggests that most sand fairways, dominated by deep marine facies, were sourced from an active Atlantic Margin Arch via northwest–southeast-oriented fluvial and shelfal feeder systems. Application of this model to Central and Northern North Sea hydrocarbon fairways suggests a gross current underestimate of Aptian sand volumes and considerable upside potential both within the Moray Firth basins and unappraised exploration territory in the Viking Graben and Central Trough.
The discovery of Goldeneye: Kopervik prospect and play mapping in the South Halibut Basin of the Moray Firth
Authors: WILSON J. , WALL G. , KLOOSTERMAN H. J. , CONEY D. , CAYLEY G. , WALKER J. , LINSKAILL C.
Published: April 2010

Exploration within the Kopervik play is impeded by difficulty in imaging the Kopervik Sandstone on seismic data due to the lack of acoustic impedance contrast between the sandstones and overlying shales. The exploration method employed in the mapping of the Kopervik play fairway of the South Halibut Basin on poorquality 3D seismic data, leading to the Goldeneye Field discovery, is described. In the early 1990s, Shell/Esso acquired acreage in the South Halibut Basin based on the identification on 2D seismic data of a number of potential stratigraphic traps in the Kopervik play. The first well targeted an Apto-Albian isochron thick, just south of the proven Kopervik fairway, but encountered no reservoir. Subsequent mapping better delineated the fairway as being restricted to the southern fringe of the South Halibut Shelf. The basal sequence boundary was mapped locally on 3D seismic data and amplitude extractions were interpreted as showing erosion at the base of the Kopervik channel complex. At the northern edge of this fairway, a small four-way dip closure identified above Goldeneye on a regionally mappable seismic reflector did not conform to deeper structure, suggesting the presence of a thick section of mounded Kopervik Sandstone. The presence of gas/condensate in thin Jurassic sandstones in a well immediately north of this closure, far removed from the Jurassic gas kitchen, suggested that long-distance migration had occurred along the Kopervik fairway and hence that gas might be trapped at Goldeneye. The Goldeneye discovery well, drilled in 1996, encountered a 305 ft column of gas/condensate above a thin oil rim within the thickest section of Lower Cretaceous Kopervik Sandstone so far encountered in the Outer Moray Firth. Subsequently, two further prospects were drilled with mixed results. The Goldeneye structure is now considered unique within the Ettrick sub-basin of the South Halibut Basin.
Exploration history of the high-pressure, high-temperature plays: UK Central North Sea
Authors: ERRATT D. , NICHOLSON P. H. , WINEFIELD P. , MILTON-WORSSELL R. J. , CAYLEY G. T. , ARTER G.
Published: April 2010

The 40-year history of the pre-Cretaceous high-pressure – high-temperature (HPHT) plays of the UK CNS is described. The exploration and exploitation of this basin has been achieved by remarkable developments in seismic, drilling and development technologies. These advances have provided predictive geological models to address significant multiple risk elements, and the ability to drill and develop reservoirs safely in HPHT conditions with temperatures in excess of 300° F, reservoir pressures exceeding 10 000 psi and surface to reservoir pressure gradients in excess of 0.8psi/ft. UK Continental Shelf exploration acreage was first awarded in 1964 in the First Licence Round. At this time seismic data did not image the Base Cretaceous surface and early drilling activity focused on the Tertiary and on obvious salt supported anticlines or major basement ridges. The subsequent period from 1968–1972 saw the discovery of the first hydrocarbons in the pre-Cretaceous in graben margin structures or on mid-graben highs, but the deeper HPHT realm remained untested. In the 1970s the discovery of the Auk, Argyll and Fulmar Fields established potentially significant plays around the fringes of the basin. However, exploration for pre-Cretaceous reservoirs in the deeper parts of the basin where HPHT conditions occurred faced significant operational obstacles. As these were overcome the 1980s saw the extension of pre-Cretaceous plays into the HPHT realm, with deep, high-quality reservoirs occurring at depths in excess of 15000 feet. This exploration phase resulted in the discovery of significant reserves at the Elgin, Franklin, Shearwater, Jade and ETAP fields. Throughout the exploration history of the CNS, the accurate prediction of deep reservoir distribution and quality and top seal integrity have been crucial to success. Innovative seismic technologies will play a key part in reducing the remaining uncertainties in these play elements.
Jade Field: an innovative approach to high-pressure, high-temperature field development
Authors: JONES A. D. , AULD H. A. , CARPENTER T. J. , FETKOVICH E. , PALMER I. A. , RIGATOS E. N. , THOMPSON M. W.
Published: April 2010

The Jade Field is located in Block 30/2c in the UK Central North Sea and was discovered by well 30/2c-3 in 1996. It was then appraised by well 30/2c-4 in 1997, with first production in 2002. The decision to develop the field after only one appraisal well led to a degree of uncertainty in the field reserves and estimated production profiles. Consequently, the development programme was designed to include an element of further appraisal. The development plan included simultaneous drilling and production operations so reservoir pressure depletion, due to production, was recognized as a significant project challenge. Detailed contingency plans were formulated to ensure that well objectives were achieved, despite the potentially problematic reservoir conditions. The field produces gas and condensate from the Triassic Joanne and Judy Sandstones and is classified as a high-pressure, high-temperature field, with a wet gas-in-place estimate for the Joanne Sandstone of around 1000 BCF and for the Judy Sandstone of 150 BCF. This paper outlines the petroleum geology and development history of the field and the current understanding of these complex reservoirs.
Extending the life of the Varg Field, a tail-end production opportunity
Authors: BATTIÉ J. E. , SIGGERUD E. I. H. , TVEITEN O. G.
Published: April 2010

The Varg Field is located in the Norwegian North Sea, by the UK border
c
. 240 km west of Stavanger. The Varg Field (Licence PL 038) is unique on the Norwegian shelf because it is the first successful tail-end production by a new and small operator, Pertra AS. Since the acquisition of the licence, Pertra has achieved higher production levels and better reservoir management in the Varg Field due to careful re-evaluation of all available data and close collaboration between different disciplines to improve the understanding of the subsurface. This paper outlines how an improved understanding of the subsurface has been achieved through a range of specialized geological and geophysical techniques, such as: ichnofabric analysis, dipmeter and wellbore image analyses, re-evaluation of the bio- stratigraphical data, trace inversion, forward seismic modelling and fluid substitution modelling. As part of the Pertra work programme, a new multi azimuth seismic dataset was acquired. After pre-stack depth migrating, this became a new and valuable dataset for reservoir description. The enhanced oil recovery analysis, utilizing all the above re-evaluated data, has yielded positive results in terms of new reserves and increased production levels.

From an economics point of view the cost of more geo-manpower is negligible when compared to the cost of the development. This has been the most important lesson learnt.
Managing reservoir uncertainty after five years of field life: Britannia Field
Authors: SUMNER W. R. , LOUTIT S. , TOHILL E. , WAY D. , CRIDDLE D. , PALFREY A. , HAKES W. G. , ARCHER S. , COLLERAN J. , SCOTT A. , KAISER K. , HARDING A. , CASTELLINI A. , CLARK J. , LIANSHUANG QI
Published: April 2010

The Britannia Field, located 210 km northeast of Aberdeen, is the largest Lower Cretaceous condensate gas accumulation in the North Sea. The field spans four UK blocks (250km
2
) and is a combination structural/stratigraphic trap. Assessing the remaining uncertainty in a field the size of Britannia is crucial to future development planning scenarios. After five years of field life, it has proved vital to take the ‘reservoir pulse’ and to evaluate the key reservoir parameters that impact the future development of the field.

The Britannia reservoir consists of deep-water mass-flow sandstones, ranging from high density ‘clean’ turbidites to non-reservoir facies consisting of ‘mixed-slurry’ and debris flows. Post-depositional remobilization and slumping have modified the original depositional fabric; however, a wealth of core data (over 20000 ft), along with 63 logged wells and dynamic production data, have allowed refining of the flow unit definition within the reservoir. A rigorous re-correlation study based on the integration of biostratigraphy, chemostratigraphy and pressure data has defined an overall sheet-like reservoir architecture, with some units exhibiting a more complex channel-like geometry (Zones 30/40).

The Britannia reservoir teamhas capitalized on recent advances in reservoir modelling technology, including a more rigorous approach to uncertainty analysis in both the static and dynamic realm. The results from a dynamic uncertainty study have provided key information on the range and magnitude of key petrophysical parameters and their impact on reservoir performance and ultimate recovery. Weighing the impact of a deterministic versus stochastic approach has also been a critical factor in the facies distribution. The major uncertainties in the dynamic reservoir model that impact reserves and recovery factor are (1) original gas in place, (2) fault and/or stratigraphic transmissibility ‘baffles’, (3) effective permeability, and, (4) condensate banking. In the static geological model, Jacta – a Gocad uncertainty module – has led to over 300 realizations of the full field model. In the dynamic realm, experimental design was used to monitor reservoir performance by capturing the variables having largest impact on dynamic flow behaviour and gas recovery.
Geologically based estimation of
k
v
/
k
h
ratios: an example from the Garn Formation, Tyrihans Field, Mid-Norway
Authors: ELFENBEIN C. , HUSBY Ø. , RINGROSE P.
Published: April 2010

During reservoir model building, one encounters several stages where upscaling or averaging of petrophysical data is required; core plug data have to be compared to wireline measurements and wireline measurements are averaged to the scale of building-size reservoir grid cells. Simple averaging does not, in most cases, give representative values, since the property in question is very scale-dependent. This is especially true for permeability and permeability anisotropy (
k
v
/
k
h
).

For the case of a reservoir model of the Garn Formation (Middle Jurassic) in the Tyrihans Field, a simple geologically based upscaling method including the use of the SBED
TM
software package has been developed. Small-scale models of near well-bore geology are upscaled using single-phase flow simulation to obtain directional-dependent permeabilities for facies with different mud contents and style. The resulting
k
v
/
k
h
estimation curve has been implemented in the reservoir model by modelling
V
shale
as a continuous parameter and applying the function to derive upscaled horizontal and vertical permeability grids. Upscaled permeabilities were found to closely match the well test data.

This approach gives a more realistic
k
v
/
k
h
ratio than traditional methods involving simple averaging, or arbitrary guesses, of vertical permeability.
Judy Field: rejuvenation through a second phase of drilling
Authors: KELLER T. , BAYES R. , AULD H. , LINES M.
Published: April 2010

The Judy Field pre-Cretaceous reservoirs produce from a series of tilted fault blocks that form a complex northwest-plunging horst in Block 30/7a, UK Central North Sea. The primary producing reservoir of this field is the Middle to Late Triassic Joanne Sandstone Member of the Skagerrak Formation with secondary contributions from the Middle Triassic Judy Member of the Skagerrak Formation and the Late Jurassic Fulmar Formation. Fluid properties and contacts vary throughout the field. Currently the field is producing from ten development wells.

Based on core studies, the depositional environment of the Triassic Skagerrak Formation has been identified as ephemeral fluvial while the Jurassic Fulmar Formation is transgressive shallow marine. Sedimentological interpretation of core data from seven wells in the field indicates that the Joanne and Judy Sandstone Members comprise four major facies associations: fluviatile channel sandstones, sheetflood sandstones, argillaceous sandstones and lacustrine mudstones. The complex architecture of these four facies associations makes it difficult to accurately predict absolute reservoir productivity without recourse to long-term production tests. Although the reservoir complexity was appreciated from an early stage in the field development, the initial reservoir models proved to be somewhat simplistic and overestimated the length of the production plateau.

Anew, longer offset 3D dataset was acquired in 1999 to replace the original pre-development 1986 3Dseismic volume. The 1999 data were designed to enhance the imaging of the pre-Cretaceous reservoirs and help define areas of additional potential, which could be developed through new high angle platform wells. Mapping of reflectors below the Base Cretaceous Unconformity with the newdata remains problematical due to poor signal to noise ratio and short period multiples. Despite these difficulties, a revised interpretation of the crestal portion of the Judy structure was completed. This new interpretation was coupled with the results from a detailed review of the geochemical, pressure and fault seal data, to create a petroleum charge model which accounted for the variations in fluid types and contacts throughout the field and identified three fault blocks (30/7a-P16, P17 and P18) in the crestal portion of the field for infill drilling. The fault blocks were successfully drilled in 2001 and 2002 despite significant drilling challenges posed by depleted reservoir zones above the target formation.
Shearwater (UK Block 22/30b): managing changing uncertainties through field life
Authors: GILHAM R. , HERCUS C. , EVANS A. , DE HAAS W.
Published: April 2010

Development of the Shearwater Field, a deep gas-condensate accumulation in the HPHT region of the UKCS, began in 1997 with the initiation of development drilling and construction of topside facilities. It formed part of the major development of the Central North Sea HPHT gas play throughout the late 1990s, together with other gas developments across Elgin/Franklin and Erskine. As such, Shearwater should be viewed, together with these other structures, as part of an expansion of the gas sector in the North Sea in an area of challenging subsurface conditions and limited development experience to constrain production uncertainty. Field sanction was based on the understanding and modelling of key subsurface uncertainties. Development experience since then has tested that initial subsurface view and lessons learnt will provide a key analogue to help constrain the development of any future HPHT gas accumulations. This paper describes the subsurface model for the Shearwater structure and how recent development experience and production performance has constrained the reservoir characterization uncertainty of the Fulmar Formation.
Imaging magmatic rocks on the Faroes Margin
Authors: ROBERTS A. W. , WHITE R. S. , LUNNON Z. C. , CHRISTIE P. A. F. , SPITZER R. ,   iSIMM TEAM
Published: April 2010

Break-up of the North Atlantic in the Paleocene was accompanied by widespread magmatism, which provides a challenge both to imaging basin structure and to modelling the subsidence and development of the continental margins. The rationale for new methods of seismic acquisition and modelling are reported here, followed by an illustration of the techniques with data from the Faroes region, which lay close to the hottest part of the mantle plume at the time of continental break-up. Igneous rocks were added to the crust during continental break-up on rifted margins as extrusive lavas, as sills intruded into the subsurface, and as lower crustal intrusions or underplate. Each provide different, but tractable problems to seismic imaging. It is shown that many of these difficulties can be surmounted by using very long offsets (long streamers or two-ship methods) with a broad-band, low-frequency source, and by using dense arrays of ocean bottom seismometers to provide complementary P- and S-wave velocity control. These methods are illustrated using new results from the integrated Seismic Imaging and Modelling of Margins (iSIMM) project, which acquired regional data across the Faroes shelf and margin in summer 2002. The iSIMM profile used 85 four-component ocean bottom seismometers and a 104 litre (6340 in
3
) airgun array for wide-angle data, with vertical arrays for far-field source signature recording. The wide-angle profiles were overshot using three single-sensor, Q-Marine streamers, one 12 km long, the other two 4 km long. A 48-gun, 167 litre (10 170 in
3
) deep-towed, broad-band airgun array was used with the Q-marine streamers. The airgun arrays were designed and tuned to enhance the bubble pulses, with peak frequencies at 8–11 Hz. They performed well, with excellent arrivals visible to ranges beyond 120 km on the OBS, and penetration through the basalts and well into the upper mantle. Examples are shown of the new seismic data, which enable imaging of the basalt flows and underlying sediments, as well as lower-crustal igneous intrusions. This allows good constraints to be placed on the igneous distribution and volumes on the rifted margin and adjacent continental shelf.
Sedimentary evolution of the Lower Clair Group, Devonian, West of Shetland: climate and sediment supply controls on fluvial, aeolian and lacustrine deposition
Authors: NICHOLS G. J.
Published: April 2010

Sandstone units in the Middle to Late Devonian Lower Clair Group form the reservoir in the Clair Field, UKCS Block 206, West of Shetland. The sandstone facies vary from thick, well-sorted, medium sands deposited by aeolian processes, to amalgamated fluvial channel deposits of coarser sand, to thin sheets of fine sand deposited in floodplain or shallow lake settings. The distribution of these different facies within the basin-fill succession was controlled by the locations of sediment supply into the basin and the climatic controls on the processes of sand distribution and sedimentation. Six lithostratigraphical subdivisions (Units I to VI) are differentiated by changes in the predominance of fluvial, aeolian and lacustrine facies. During periods of high sediment supply and relatively humid climate (Units II, IV and V), fluvial conditions dominated in the form of sandy to pebbly fluvial distributary systems laid down as terminal fans. The water-lain sandstone facies characteristics vary from stacked, coarse channel fills deposited by braided rivers (Unit II) to decimetre sand sheets interpreted as the deposits of poorly channelized flow at the margins of the terminal fan (Unit V). At times of relative aridity, the fluvial system retreated and aeolian reworking resulted in extensive sheets of well-sorted sands deposited as dunes or on sand flats (Unit III). Periods of wetter climate and reduced clastic input resulted in widespread lacustrine conditions. Lakes were fed by rivers which terminated in lake deltas ranging from coarse, fan deltas (Unit I) to fine-grained deltas (Unit VI). The Devonian Clair Basin is an example of deposition in a basin of internal drainage which was predominantly controlled by climate and sediment supply variations. A predictive model for sandbody character and distribution can be developed using an understanding of these controls on the evolution of continental depositional systems in the basin.
Aspects of the Cenozoic deformational history of the Northeast Faroe–Shetland Basin, Wyville–Thomson Ridge and Hatton Bank areas
Authors: JOHNSON H. , RITCHIE J. D. , HITCHEN K. , MCINROY D. B. , KIMBELL G. S.
Published: April 2010

The nature and age of the Cenozoic compressional/transpressional deformation within the NE Faroe–Shetland Basin, the Wyville–Thomson Ridge and Hatton Bank areas have been investigated, primarily using seismic reflection data. In all three areas, the folds reach approximately 2 to 4k min amplitude and 40k min wavelength. Early and mid-Eocene compressional/transpressional deformation affected the Hatton Bank and Wyville–Thomson Ridge areas, and folding was locally active even earlier, during Paleocene/Cretaceous times. However, the main Cenozoic compressional/transpressional tectonism that affected the Hatton Bank area was coeval with development of the regional Late Eocene Unconformity (C30), and with changes in spreading geometries and a phase of accelerated subsidence in the Rockall Basin. Within the NE Atlantic margin, WNW-to NW-trending lineaments/transfer zones and associated oceanic fracture zones facilitate significant structural segmentation. Offsets in the continent–ocean boundary along Hatton Bank probably reflect inherited basin architecture, and many Cenozoic folds in the Hatton Bank, Wyville–Thomson Ridge and NE Faroe–Shetland Basin areas are considered to mainly reflect compressional buttressing against pre-existing structures. However, relatively small lateral displacements probably occurred along some reactivated transfer zones following continental break-up. Paleocene–Eocene compressional/transpressional deformation may have affected parts of the Faroe–Shetland Basin, but seismic resolution of this is largely masked by pervasive polygonal faulting. Significant, early to mid-Miocene compressional/transpressional deformation is recorded in the NE Faroe–Shetland Basin, and may also have exerted a major influence on the Wyville–Thomson Ridge and surrounding area. In particular, mid-Miocene growth of the Faroe Bank Channel syncline may have resulted in major changes in northern hemisphere deep-ocean circulation with associated impact on global climate. Compressional/transpressional deformation appears to have continued into Pliocene– ?Recent times and resulted in the development of features such as the Pilot Whale Anticline and associated mud volcanoes/diapirs.
The Corrib gas field, offshore west of Ireland
Authors: DANCER P. N. , KENYON-ROBERTS S. M. , DOWNEY J. W. , BAILLIE J. M. , MEADOWS N. S. , MAGUIRE K.
Published: April 2010

The Corrib Gas Field in the Slyne Basin lies about 70 km west of Co. Mayo, offshore Ireland. The basin is a narrow Triassic/Jurassic half-graben and is one of a series of structurally linked basins that are present along the west coast of Ireland and the British Isles. The field was discovered in 1996 by well 18/20-1, encountering a 61 m gas column in low-porosity Triassic fluvial sandstones at a subsea depth of 3539.6 m. Using extremely poor 2D seismic data, it was originally mapped as a tilted fault block, with an associated rollover structure to the east. The data quality was particularly poor due to the near-surface Palaeogene volcanics that contribute to energy dispersion and extreme multiple generation. A 3D seismic survey was acquired in 1997 and resulted in a major improvement in data quality, allowing improved structural interpretation that showed the Corrib Field to be a faulted anticline. The subsequent appraisal well, 18/20-2z, drilled approximately 1 km from the subsurface location of 18/20-1, penetrated a 185 m gas column in fair to good quality sandstone. It tested dry gas at a stabilized rate of 62.87 × 10
6
SCF/d on a 2″choke. Reprocessing of the seismic data, along with the successful drilling of the following well 18/25-1, confirmed the field to be a relatively simple anticlinal trap, with a complex faulted overburden that is structurally detached from the reservoir by the Mercia Halite. The source rock is assumed to be the Westphalian Coal Measures, similar to that encountered by well 27/5-1. The dry gas is consistent with a Type-III humic source rock. The reservoir is biostratigraphically barren, consisting of fluvial red bed sandstone, and is assumed to be of Triassic Sherwood Sandstone Group equivalent age. The unit is approximately 400 m thick, consisting of a high net-to-gross sequence of low-sinuosity braided fluvial channel sandstones with subordinate sand-flat and playa mudstone deposits. On a macro scale, it is a remarkably uniform sandstone with only subtle facies variations, but on a micro scale there is a significant variation in grainsize and cementation, which affects reservoir productivity. Mineralogically, there are distinct differences from the Sherwood Sandstone Group of the East Irish Sea, indicating that the Slyne Early Triassic system was depositionally similar to, but distinct and separate from, that to the east of Ireland. Dipmeter data indicated that the river system flowed from the SW to NE, essentially along the direction of the present-day Slyne Basin, suggesting that it was largely sourced from the south in the Variscan hinterland, but with evidence of sediment input from local highs such as the Connemara Massif.
First results from shallow stratigraphic boreholes on the eastern flank of the Rockall Basin, offshore western Ireland
Authors: HAUGHTON P. , PRAEG D. , SHANNON P. , HARRINGTON G. , HIGGS K. , AMY L. , TYRRELL S. , MORRISSEY T.
Published: April 2010

The results of an integrated sedimentological and seismic stratigraphical analysis of three borehole sites on the eastern flank of the Rockall Basin, offshore western Ireland are reported. Two sites were drilled on the western slope of the Porcupine High, above the North and South Bróna basins (boreholes 83/20-sb01, 83/24-sb01 and 83/24-sb02), and one on the northern flank of the Porcupine High (16/28-sb01), above the Macdara Basin. The cores establish that the half-graben basins marginal to the eastern Rockall Basin contain Jurassic deposits and that they were inverted sometime in the Late Jurassic or Early Cretaceous. An angular unconformity above the Bróna basins is overlain by a condensed, tripartite Cretaceous succession (‘brownsand’, ‘greensand’, chalky micrite) that records stepwise deepening, with evidence for a Cenomanian-Turonian phase of normal faulting. Above the Macdara Basin, the unconformity is overlain by a basalt that was cored at the 16/28 site and is interpreted to represent a flow of Cretaceous age derived from the Drol Igneous Centre. At all three borehole sites, Cretaceous strata are onlapped (or downlapped) by Paleocene-Eocene strata that display evidence of a minor episode of fault reactivation above the Bróna basins. Cored Eocene strata vary from clastic to carbonate-prone from north to south and smectitic clays are common at the 16/28 site. Post-Mid-Eocene westward tilting of the Rockall slope rotated the Eocene stratigraphy and the underlying Cretaceous deposits (including the lava flow in the 16/28 area) at least 3° down to the west. Slope development resulted in extensional sliding and the erosion of the C30 deep-water unconformity that is onlapped by Miocene slope deposits. C30 was cored in the 83/20 area where it cuts down into Cretaceous strata and is crusted with phosphates and the Cretaceous beneath Mn-impregnated.
Reconstructing the Mesozoic–Cenozoic exhumation history of the Irish Sea basin system using apatite fission track analysis and vitrinite reflectance data
Authors: HOLFORD S. P. , TURNER J. P. , GREEN P. F.
Published: April 2010

This paper summarizes new and recent apatite fission track analysis and vitrinite reflectance results from across the Irish Sea basin system and its margins, which provide new constraints on the magnitude and timing of post-Palaeozoic exhumation across this area. In particular, these results suggest that this region has experienced a complex, multi-phase exhumation history. Distinct episodes of kilometre-scale exhumation occurred during the early Cretaceous, early Palaeogene and late Palaeogene–Neogene times, with the overall magnitude of exhumation in each episode decreasing over time. Regional early Cretaceous exhumation removed up to 3 km of section from the Irish Sea basins, and appears to be related to incipient Atlantic rifting. Early Palaeogene exhumation attained up to 2 km and was driven by a combination of localized tectonic inversion and regional epeirogenic uplift, although early Palaeogene palaeotemperatures within parts of the Irish Sea basin systemare dominated by non-burial-related processes. A final phase of exhumation, related to late Palaeogene– Neogene tectonic inversion, uniformly removed
c
. 1 km of section from this region. Given that these exhumation episodes coincide temporally with important periods of deformation at pre-existing or incipient plate boundaries, events at plate margins are interpreted to have exerted the primary control on the Mesozoic–Cenozoic exhumation of the Irish Sea basin system.
Submarine fan morphology and lithology distribution: a predictable function of sediment delivery, gross shelf-to-basin relief, slope gradient and basin topography
Authors: HADLER-JACOBSEN F. , JOHANNESSEN E. P. , ASHTON N. , HENRIKSEN S. , JOHNSON S. D. , KRISTENSEN J. B.
Published: April 2010

Over the last decade comprehensive exploration for turbidite plays has been rewarded by a significant number of hydrocarbon discoveries. However, the industry is still critically challenged with respect to appropriate and refined prediction of sand/shale distributions within these depositional systems. Along with a strong and sustained commercial interest in these plays, extensive subsurface datasets, including a new generation of core- and well/log-calibrated seismic facies suites, have become available.

Based on this valuable information, systematic 2D and 3D seismic sequence stratigraphical analysis with particular focus on seismic facies and seismic geomorphology was performed in five different basins along North and South Atlantic margins. Each subsurface example was characterized with reference to its relative sequence stratigraphic order within a hierarchy. Evolving geological parameters like shelf accommodation, shelf-break position, slope gradient, slope and basin bathymetry/topography and third-, fourth- and occasionally fifth-order stacking patterns were assessed within second-order cycles in each case. Based on these observations, recognition criteria for subsurface lithology prediction were derived. Conceptual knowledge from outcrop analysis was an essential and integral part of the interpretation process throughout the study.

The subsurface recognition criteria, highlighted in this study, emphasize similarity and variability between two end-member basin styles: high shelf-to-basin relief/sediment under-filled basins where sand-prone nearshore systems do not prograde over deep-water fan systems in a second-order cycle context; low shelf-to-basin relief/sediment over-filled basins where sand-prone nearshore systems do prograde over deep-water fan systems in a second-order cycle context.

The most striking contrast with respect to deep-water reservoir sandstone distribution in the two basin categories relates to the fourth- and fifth-order stacking patterns of fan building-block cycles within second- and third-order cycles, which tend to show low progradation/aggradation ratio in the high relief basins and high progradation/aggradation ratio in the low relief basins. Given an understanding of geological context, these seismically identifiable patterns provide more accurate prediction of sand and shale distribution within deepwater clastic systems.
The reservoir development of the Late Maastrichtian–Early Paleocene Ormen Lange gas field, Møre Basin, Mid-Norwegian Shelf
Authors: GJELBERG J. , MARTINSEN O. J. , CHARNOCK M. , MØLLER N. , ANTONSEN P.
Published: April 2010

The giant Ormen Lange Gas Field is situated in the Møre Basin, Norwegian Sea, at water depths around 1000 m. The reservoir interval consists of a lower heterolithic unit mainly of Maastrichtian age (Jorsalfare Formation) and an upper sandstone unit of Danian age (Egga Member, Våle Formation), separated by a widely distributed mudstone unit (‘Våle Tight’), and consists of both high and low density turbidites in association with fine-grained background sediments. The reservoir interval spans the Cretaceous–Tertiary boundary, without any major stratigraphic breaks. The main architectural elements of the reservoir are: channel-dominated deposits, channelized lobe deposits and non-channelized frontal splay or fan fringe deposits. The spatial distribution of these facies elements indicates a dynamic system with changing sediment supply through time. Core and log studies from the wells have been integrated with high-resolution biostratigraphy to develop a dynamic depositional model.

During latest Cretaceous and Paleocene times, a series of subtle sub-basins developed along the southeastern Møre Basin margin as a result of differential subsidence above Jurassic extensional faults. The sub-basins created a stepped slope topography that influenced the flow pattern of turbidity currents.

In a landward position, east of the Ormen Lange Field, the Cretaceous–Tertiary boundary is characterized by a major unconformity, implying erosion and sediment by-pass. In early Danian time, uplift and rotation of the provenance area to the east (Norwegian mainland) led to extensive erosion and redistribution of sandy sediments into the Møre Basin and caused deposition of the Egga Member. The turbidites filled the intraslope basins initially in a basinwards-stepping sense, but later sedimentation switched landward.

Onshore structural, provenance and geomorphological data, combined with offshore structural, seismic and sedimentological data, yield an integrated interpretation of the deep-water depositional system in the greater Ormen Lange area. Present fjords at Møre, controlled by the Møre–Trøndelag fault zone, were valley systems that fed sands to a point source updip of the Ormen Lange area. The point source was located at the transition/relay zone between a narrow shelf area in the south and a broad shelf area in the north. In addition to being a key transition zone for both Caledonian and Jurassic structures, this zone area is also the ‘landing’ point of the major oceanic Jan Mayen Fracture Zone.
Using multicomponent seismic data to better characterize and manage reservoirs
Authors: KRISTIANSEN P. , WAGGONER J.
Published: April 2010

Multicomponent seismic data (3C on land/4C on seabed) have unique information content that has proven to be useful in structural interpretation. As such, development of 3C/4C seismic acquisition, processing, and interpretation systems has increased over the past few years within the geophysical community. These improvements have shown that 3C/4C seismic information has application beyond structural interpretation, and can reveal internal reservoir characteristics that are directly useful in understanding and managing the reservoir.

After reviewing the principles, applications, benefits and recent advances in 3C/4C seismic technology, all from an engineering perspective, this paper concludes that 3C/4C seismic has utility beyond the known niche applications such as imaging beneath gas clouds, to applications with broader benefit, such as fracture characterization and drilling hazard identification, as well as better reservoir property prediction and the ability to discriminate lithology (sand/shale) and fluid (water, gas, fizzy water). These conclusions are illustrated with recent case studies.
Advances in subsurface imaging using potential field technology: gravimetry sensors and applications
Authors: SMIT D.-J. , BIEGERT E. , MONDT J.
Published: April 2010

Recent advances in resolution and sensitivity of potential field sensors could fundamentally change subsurface risk management. Gravity gradiometer data have been fully integrated in the cycle of iterative pre-stack depth migration (PreSDM) model, updating to arrive at a high-fidelity subsurface model in complex geological settings where seismic data is inevitably of poor quality. Upon integrating potential field data, for example provided by new instruments currently available, it will be shown that significantly improved seismic imaging can be achieved near salt overhangs (sub-salt) as well as below hard layers. Based on results so far it is concluded that the potential of this technology could substantially change the role of gravity field measurements in the process of subsurface de-risking. The resolution and interpretation issues of existing gravity gradiometer data are explored and their utility with several case studies demonstrated.
Bile-induced secretion of glucagon-like peptide-1: pathophysiological implications in type 2 diabetes?
Authors: Knop Filip K.
Published: April 2010

During the last decades it has become clear that bile acids not only act as simple fat solubilizers, but additionally represent complex hormonal metabolic integrators. Bile acids activate both nuclear receptors (controlling transcription of genes involved in for example bile acid, cholesterol, and glucose metabolism) and the cell surface G protein-coupled receptor TGR5 (modulating energy expenditure in brown fat and muscle cells). It has been shown that TGR5 is expressed in enteroendocrine L cells, which secrete the potent glucose-lowering incretin hormone glucagon-like peptide-1 (GLP-1). Recently it was shown that bile acid-induced activation of TGR5 results in intestinal secretion of GLP-1 and that enhanced TGR5 signaling improves postprandial glucose tolerance in diet-induced obese mice. This Perspectives article presents these novel findings in the context of prior studies on nutrient-induced GLP-1 secretion and outlines the potential implications of bile acid-induced GLP-1 secretion in physiological, pathophysiological, and pharmacological perspectives.