Abstract Each of the Earth's approximately 900 sedimentary basins is a unique result of geologic, hydrologic, atmospheric and biologic processes. The interaction of these processes results in complex histories that are palaeogeographically linked within tectonic provinces. Process-based genetic analysis provides the fundamental framework for predicting the distribution and character of petroleum systems. New technologies enable the exploitation of this predictability and are themselves the origin of new ideas and improved systems understanding. Petroleum geoscience embraces both forward modelling of processes as well as observation, calibration and inverse modelling. This approach of forward and inverse modelling promotes a general scientific methodology of simulation, prediction, testing and learning that allows us to describe the genetics of sedimentary basins. Genetic analysis can be applied to the spectrum of resource types from hydrocarbon to groundwater to mineral systems and across the range of scales from regional to play to prospect. Like the study of evolution through the fossil record, fundamental characteristics of petroleum systems can be recovered from the patterns of their distribution within the framework provided by plate motion, palaeogeography and palaeoclimate. These fundamental drivers control regional tectonics, subsidence, fill history and deformation that result in the phenotypic expression of individual basins and their fluid systems. Genetic analysis results in a taxonomic hierarchy that facilitates prediction and guides resource exploration. Although genetic analysis provides a framework for understanding the distribution and nature of petroleum systems, that framework itself is insufficient to address the challenges now facing the petroleum industry. New technologies are required to enable exploration in frontier settings, to identify new opportunities in mature basins, to maximize recovery from existing fields, and to unlock the potential of unconventional resources. Future success in all of these areas is fundamentally dependent on our ability to conceptualize new ideas.

Abstract An opportunity to discuss and publically debate three critical issues of concern to oil company geologists was introduced into the Petroleum Geology Conference (PGC) programme for the first time in 2009. The debates selected focused on whether “peak oil” was already upon us; the relative role of National Oil Companies (NOCs) versus that of International Oil Companies (IOCs) and whether North Sea Exploration was finished. In each case, the arguments were delivered by two experts, who presented the case for and against each motion before answering questions and facing a vote by the audience, who showed coloured cards to indicate their support for what they had heard. All three debates proved to be extremely popular and were very well attended for all three days. The novel concept was deemed a great success and added significant value to the PGC.

Abstract Significant advances in geosciences data acquisition, visualization and analysis now allow highly detailed outcrop models to be constructed for a range of petroleum industry purposes. From a given field locality, a virtual outcrop is created from a centimetre-scale digital elevation model and colour photographs with geological information overlaid as appropriate. In a visualization environment, these datasets can be viewed sequentially to simulate undertaking a fieldtrip. These virtual fieldtrips allow geoscientists to improve and expand the traditional fieldwork experience in a number of ways, ranging from planning and health and safety considerations for management, to providing live supplemental technical content on a mobile device to the fieldtrip participant. The fieldtrips are easily archived and content can be reviewed in the office to provide analogue information during technical work. Examples of virtual fieldtrips are provided on the DVD that accompanies this volume.

Abstract The core workshop followed the format of the three core events at previous Petroleum Geology Conferences (e.g. Oakman & Martin1993), although it was smaller in scale and its focus was on the reservoir sedimentology of the North Sea. The workshop was organized by the British Sedimentological Research Group (BSRG)with the cooperation of the Petroleum Exploration Society of Great Britain (PESGB) and British Geological Survey (BGS),who provided and transported all of the cores on display. BSRG exists to promote and support the work of young researchers in sedimentary geology (including stratigraphy, diagenesis, process sedimentology and geochemistry), many of whom go on to successful careers in the oil industry. Within this context, the workshop featured presentations by PhD students, academics and consultants that put the reservoirs illustrated by the cored intervals into context,from both a depositional and a commercial standpoint.

Abstract Over 35 years, the Petroleum Geology Conference series has been the leading UK conference dedicated to making public the scientific advances and findings of some four decades of NW European hydrocarbon exploration and production. Leading edge issues in the NW European province after four decades include small pool and high pressure high temperature (HPHT) exploration, late-stage field exploitation and field redevelopment. The rich subsurface datasets and pioneering of emerging technologies provide a stream of valuable models, lessons, techniques and ideas which have both local and international applicability. Papers grouped under the exploration theme contain regional, local and detailed studies which illustrate the nature of current exploration activity for small, deep and complex structural and stratigraphic prospects. Closer and more comprehensive integration of seismic-derived understanding of structural evolution and seismic, well and analogue-derived depositional and sequence stratigraphic constraints are probably the most fruitful approaches and are shown by a number of papers. Papers on field development and production themes describe the industry's response to challenges such as low permeability and reservoir prediction through the use of multiple 3D and 4D seismic datasets and the exploitation of advances in drilling, well logging and completion technologies to drain progressively smaller per well reserves. Again, integration is the watchword, here between interpretations and analyses of subsurface data with well planning and construction. Finally, a number of papers describe current techniques in petrophysics, 3D and 4D seismic applications and remote sensing approaches.

Abstract A review is given of the development of the understanding of the structure and stratigraphy of a classic petroleum province through 35 years of NW European Petroleum Geology Conferences, using new examples to illustrate the interplay between tectonics and sedimentation in the development of some of the major hydrocarbon plays. Cimmerian tectonics is discussed, with regard to the evidence for regional-scale truncation beneath the Mid Cimmerian unconformity, and the stratal motifs characteristic of rifting associated with the Early and Late Cimmerian events. New data revealing the structural geometries associated with polyphase rifting in the East Shetland Basin are presented. The seismic and sequence stratigraphy of Jurassic and Cenozoic sequences are reviewed and new data presented, with a discussion of generic play controls in North Sea Jurassic deepwater reservoirs. The development of integrated hydrocarbon system studies is reviewed, and the remaining challenges to predictive capabilities discussed. The impact of advances in geoscience and technology on North Sea creaming curves is discussed.

Abstract This paper integrates interpretations of modern long-offset seismic datasets with potential field anomalies derived from dense grids of 2D gravity and magnetic data to present a regional-scale synthesis of Devonian, Carboniferous and Early Permian basin development beneath the UK Central North Sea. The 95 000 km 2 study area has had little modern exploration for petroleum systems beneath the Upper Permian. Seismic interpretation and potential field modelling confirm that along the southern fringe of the Central North Sea, as in northern England, Lower Carboniferous basin development was strongly influenced by the disposition of granite-cored Lower Palaeozoic basement blocks – Farne Block, Dogger Block and Devil's Hole High. This study adds a previously unidentified WNW–ESE trending pre-Devonian basement block, the Auk–Flora Ridge, that exerted a profound control on Late Devonian to Mesozoic structural evolution of the south-Central North Sea. From the Flora Field, where it is overlain by relatively thick mid-Devonian to earliest Permian strata, the sub-Permian relief of this block becomes progressively shallower towards the NW. On its southern flank lies a parallel half-graben, akin to the Stainmore Trough in northern England, and interpreted as also containing several thousand feet of Lower Carboniferous strata. As indicated by the coal measures section in well 39/7-1, these strata are likely to include prolific source rocks, which have been modelled as being fully mature for oil generation in Quadrant 29. Potential field modelling extends this interpretation beyond the current seismic coverage, and suggests that Carboniferous to earliest Permian basin development in the Central North Sea was strongly influenced by an underlying Scottish–Norwegian SW–NE trending Caledonoid structural fabric. An earliest Permian, Lower Rotliegend unit thickens southwards towards the Auk–Flora Ridge, and rests unconformably on one or more undrilled NE–SW trending Carboniferous basins. Red-bed fluvial facies akin to those at Flora are likely to dominate the substantial post-Dinantian fill of these basins, but significant thicknesses of Westphalian coal-measure source rocks may also be present locally. As in central Scotland, the Dinantian strata underlying a widespread mid-Carboniferous unconformity in these basins are likely to contain further coal-measure intervals and local developments of oil-shale source rocks. These Westphalian and Dinantian source rocks are key elements of a Carboniferous petroleum system that remains largely untested across large areas of the Central North Sea.

Abstract Channel horizons, delimiting a major Pliocene sedimentary prism in the central North Sea basin, have been investigated in the context of oceanographic, climatic and tectonic controls, using 3D seismic and well data from the UK and Norwegian sector. Aggrading channel structures, forming 700–2500 m wide and 75–150 m deep linear to arcuate troughs, superimpose the truncated distal part of the prism in the northern Central Graben. The origin of the aggradational channel and prism complex is related to differential deposition and erosion by contour currents that intensified as tectonic subsidence formed a deep marine basin (>600 m) with open connections to the Atlantic and Norwegian Sea. The largest channel troughs appear to be filled with consolidated sediments and emerge from areas where the Neogene strata is pierced by salt diapir chimneys. From Early Pleistocene ( c . 2.5 Ma) the channels were subject to progressive burial by rapid clinoform progradation. Based on the seismic observations, a depositional model is proposed that relates contourite channel development to fluid expulsion from salt diapir structures and fracture zones extending from lower Miocene strata. The sedimentary prism accumulated over a Late Miocene/Early Pliocene Unconformity marked by incised channels that are reminiscent of a northward diverging drainage system. This erosive low-stand development is probably related to late Alpine compression, which promoted uplift in the British Isles and the Channel region. The ensuing subsidence of the central North Sea, associated with concomitant uplift of the Norwegian–Danish Basin, generated the present southwestward dip of 0.5–0.8° of the basal unconformity. The Late Miocene compressional phase followed by rapid basin depending during Pliocene to early Pleistocene suggests that present concepts of North Sea basin development have to be re-evaluated.

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

Abstract Italy is the most hydrocarbon endowed country of southern Europe, with total discovered reserves (produced+remaining) of 1840 million barrels of oil and 30 trillion ft 3 of gas. The production of oil amounts to 43.2 million barrels per year, about 75% of which comes from the Val d'Agri Field in the southern Apennines. The production of gas is 340 billion ft 3 per year, most of it coming from the northern Adriatic Sea. Hydrocarbon occurrences derive from a variety of petroleum systems which are the result of a complex geological history. At least five important source rocks have been recognized which are distributed in age from Mesozoic through Pleistocene. Three of them were deposited during Mesozoic crustal extension and are mainly oil-prone. Hydrocarbon occurrences associated with these sources are usually found in complex carbonate structures along the Apennines thrust-and-fold belt and in the foreland. Villafortuna–Trecate (Po Plain), Val d'Agri/Tempa Rossa (southern Apennines) and Gela (Sicily) fields represent the largest oil accumulations pertaining to these systems. Two other important sources rocks were deposited in the foredeep terrigenous units of the foreland basins which formed during the Cenozoic orogenesis. The older source is thermogenic gas-prone and is found in the highly tectonized Oligo-Miocene foredeep wedges: gas occurrences associated with this source are mainly concentrated along the northern Apennines margin (e.g. Cortemaggiore Field), in Calabria (e.g. Luna Field) and Sicily (e.g. Gagliano Field). The younger source is biogenic gas-prone and is situated in the outer Plio-Pleistocene foredeeps. The most important gas fields of Italy, located in the eastern Po Plain and northern Adriatic sea (Barbara and other gas fields), have originated from this source. Hydrocarbon exploration in Italy is overall mature, especially for gas, whose residual potential is estimated to be 6.0 trillion ft 3 of reserves. The remaining potential of oil is estimated to be 800 million barrels.

Abstract Recently available well data from the northern part of the Danish Central Graben have been analysed to further understand the basin development, biostratigraphy, depositional models and palaeogeography of Upper Jurassic reservoir sandstones, which are the primary exploration targets in this basin. Notably, the discovery of the Hejre accumulation in 2001, where oil has been encountered in Upper Jurassic good reservoir quality sandstones at a depth of more than 5000 m, triggered renewed interest in the Upper Jurassic High Temperature–High Pressure sandstone play in the area. Overall the Danish Central Graben was transgressed from east to west during the Late Jurassic. During the Late Kimmeridgian, marginal and shallow marine sandstones assigned to the Heno Formation were deposited at the margin of the Feda Graben, and on the Gertrud and Heno Plateaus and constitute the reservoirs in the Freja and Hejre discoveries. The sandstones are analogues to the UK Fulmar and Norwegian Ula Formations encountered in several hydrocarbon fields. During the Early Volgian, the transgression continued westwards across the Outer Rough Basin along the margin of the Mid North Sea High, where shoreface sandstones with excellent porosities and permeabilities were deposited close to similar sandstones of the Fulmar Formation in the British Fergus, Fife and Angus fields. During this overall westward transgression, the eastern and central parts of the Danish Central Graben continued to subside and offshore mudstones accumulated, locally intercalated with gravity-flow sandstones. In the easternmost Danish Central Graben, in the Tail End Graben, Upper Kimmeridgian gravity-flow sandstones of the Svane-1 well have proved the presence of gas at c . 6 km depth. Hydrocarbon-bearing Upper Jurassic sandstone reservoirs at significant depths (deeper than 5 km) may form the future exploration targets in the northern part of the Danish Central Graben.

Abstract An unusually thick ( c . 88 m), transgressive barrier island and shoreface sandstone succession characterizes the Upper Jurassic Heno Formation reservoir of the Freja oil field situated on the boundary of Denmark and Norway. The development and preservation of such thick transgressive barrier island sands is puzzling since a barrier island typically migrates landwards during transgression and only a thin succession of back-barrier and shoreface sands is preserved. Investigation of the development and geometry of the Freja reservoir sandstones is problematic since the reservoir is buried c. 5 km and seismic resolution is inadequate for architectural analysis. Description of the reservoir sandstone bodies is thus based on sedimentological interpretation and correlation of seven wells, of which five were cored. Palaeotopography played a major role in the position and preservation of the thick reservoir sandstones. Using the nearest maximum flooding surface above the reservoir as a datum for well-log correlations, the base of the barrier island succession in the wells is reconstructed as a surface with steep, seaward-dipping palaeotopography. The relief is c . 270 m over a distance of c . 8 km and dips WNW. As a complementary approach to investigation of the reservoir architecture, a Holocene–Recent barrier island system in the Danish part of the NW European Wadden Sea has been studied and used as an analogue. The barrier island of Rømø developed during a relative sea-level rise of c. 15 m during the last c. 8000 years and is up to 20 m thick. To unravel the internal 3D facies architecture of the island, an extensive ground penetrating radar (GPR) survey of 35 km line length and seven cores, c. 25 m long, was obtained. Although the barrier island experienced a rapid relative sea-level rise, sedimentation kept pace such that the island aggraded and even prograded seawards and became wider and longer due to the large surplus of sand.

Abstract The Middle Jurassic Hugin Formation has been the target of exploration within Quadrant 15 of the Norwegian South Viking Graben since the 1960s. The Hugin formation comprises shallow-marine and marginal-marine sediments deposited during the overall transgression and southward retreat of the ‘Brent Delta’ systems. Sedimentological analysis of cores across the quadrant has identified six facies associations: bay-fill, shoreface, mouth bar, fluvio-tidal channel-fill, coastal plain and offshore open marine. These facies associations are arranged in a series of parasequences bounded by flooding surfaces, several of which are correlated regionally using biostratigraphic data. Within this stratigraphic framework, facies association distributions and stratigraphic architectures are complicated, reflecting the spatial and temporal interaction of various physical processes (e.g. waves and tides) with an evolving structural template produced by rift initiation and salt movement. The overall transgression was highly diachronous, becoming younger from north to south. The northern part of the study area (Sigrun–Gudrun area) is characterized by a series of backstepping, linear, north–south-trending barrier shorelines and sheltered bays. The central part of the study area (Dagny area) contains stacked, backstepping strandplain shorelines that fringed syn-depositional topographic highs. Local angular unconformities are developed around these highs, implying that they formed above fault-block crests and salt-cored structures. The southern part of the study area (Sleipner area) contains stacked deltaic shorelines that were modified by both waves and tides. Sandbody geometry is closely related to depositional regime and syn-depositional tectonic setting within the basin; a robust understanding of both is critical to successful exploration of Hugin Formation reservoirs.

Abstract Deposition of the Callovian–Ryazanian Humber Group of the UK Central Graben occurred during rifting and long-term relative sea-level rise, which acted to suppress the formation of eustatically forced Exxon-type sequence boundaries. The superposition of highly variable halokinetically controlled subsidence means that classic, passive-margin derived sequence stratigraphic models are not appropriate to describe stratigraphic evolution in this rift setting. The sequence stratigraphy of the Humber Group has been re-evaluated using a transgressive–regressive sequence model, where maximum regressive surfaces are employed as sequence bounding surfaces. The Humber Group comprises two megasequences which reveal distinct phases of evolution of the basin. The latest Callovian–Kimmeridgian megasequence comprises a conformable sequence stack which lacks significant internal unconformities and records progressive marine flooding and overall backstepping onto the basin flanks during a phase of active rifting. The Volgian–Ryazanian megasequence is condensed and highly fragmentary due to punctuation by a number of unconformities which are consistently recognizable throughout the basin. The onset of this change in architectural style corresponds to the oldest unconformity at the base of the Volgian–Ryazanian succession, termed the Base Volgian–Ryazanian Unconformity, of latest Kimmeridgian to earliest Volgian age. The patterns of erosion of the Callovian–Kimmeridgian megasequence and the intra Volgian–Ryazanian unconformities record the effects of dramatic redistribution of underlying salt accompanied by probable uplift of the Forties–Montrose High and J Ridge, resulting in major modification of the basin morphology and the severing of possible earlier links with the Fisher Bank Basin. The kinematics of this event are equivocal, but it is possible that restricted Volgian–Ryazanian depocentres resulted from localized salt collapse rather than basement extension. Widespread erosion of Callovian–Kimmeridgian Humber Group sediments may have occurred in some areas where Volgian–Ryazanian Kimmeridge Clay deposits now overlie pre-Jurassic strata, and exploration models must incorporate the effects of Volgian reconfiguration in order to accurately predict reservoir distribution.

Abstract The Huntington discoveries are an unusual exploration success in that two oil accumulations were tested in separate syn- and post-rift reservoirs with a single well. The discoveries are located 205 km east of Aberdeen in the East Central Graben some 35 km east of Forties Field in 300 ft of water. The 22/14-5 discovery well, drilled in May 2007, encountered a 122 ft oil column in the Paleocene Forties Sandstone and also a 136 ft oil column in the Upper Jurassic Fulmar Sandstone. Both the Forties and the Fulmar contain high-quality oil, 41 and 39° api gravity, respectively. Aggregate flow rates from the two zones exceeded 11 000 boepd on test. Appraisal drilling of the Forties was completed in late 2007 with first oil targeted for 2011. The Fulmar appraisal programme is currently in progress. The Forties reservoir is a high net to gross sandstone containing stacked channel sequences deposited in a submarine fan system. The Fulmar reservoir also contains a thick sand package deposited in a shallow marine shelf setting. Pre-drill mapping based on reprocessed 3D seismic indicated a structural closure on both horizons at the location tested by the well. At both the Forties and Fulmar targets, however, the oil column height exceeded the pre-drill prognosis. This overview will focus on pre-drill perceptions of the prospect relative to actual drilling results.

Abstract The Jasmine Field is located in blocks 30/06 and 30/07a on the J Ridge, the southeastern extension of the Forties–Montrose High, which separates the eastern and western basins of the UK Central North Sea. The field was discovered in 2006 and is close to two ConocoPhillips producing fields, Jade and Judy, which serve as useful local analogues. The main West Limb structure is a turtle-back faulted anticline NW of the Joanne salt pillow. The primary reservoir is Triassic in age and consists of stacked fluvial sandstones of the Joanne Member of the Skagerrak Formation. The HPHT exploration wells 30/06-6 and geological sidetrack 30/06-6Z discovered a rich gas condensate column of 2300 ft, some 1100 ft deeper than the mapped independent structural closure of the prospect, and achieved good flow rates on test. To appraise the discovery and assess the potential for significant additional volumes in an adjacent downfaulted terrace, a programme comprising a main well and two sidetrack wells was initiated in 2007. Appraisal well 30/06-7 discovered a 550 ft hydrocarbon column in the Northern Terrace with a hydrocarbon–water contact shallower than that observed in the West Limb, thereby proving structural compartmentalization between the two fault blocks. Good flow rates were achieved from a drill stem test in mechanical sidetrack well 30/06-7Z. Sidetracks 30/06-7Y and 30/06-7X were drilled to confirm the northwestern extension of the West Limb discovery and to test the northern extent of the Northern Terrace accumulation, respectively. This programme has reduced volumetric uncertainty but the trapping mechanism and the ultimate extent of the Jasmine accumulation remain unknown. Comprehensive data acquisition throughout the exploration and appraisal phases, including drill stem testing, core recovery and seismic data reprocessing, has facilitated a detailed reservoir characterization programme. Jasmine represents a significant new high pressure/high temperature resource in the mature Central North Sea and is currently undergoing development planning.

Abstract A seismic amplitude anomaly has been identified at the Upper Paleocene T38 level in the northern Judd Basin and will be tested by the drillbit in 2009. Prospectivity at shallower levels has been largely ignored due to the fact that the main regional seal in the area was recognized to be the T35/T36 mudstones below the Kettla Tuff. Seismo-stratigraphic analysis of the T38 sequence directly above the tuff marker has identified the potential for a new play type, especially adjacent to fault zones where these mudstones are breached, allowing hydrocarbons to migrate from the Upper Jurassic source kitchen into any traps identified above the seal. In this area, the T38 is represented by a series of northerly prograding low-angle clinoforms representing the final marine infill of sediments into the basin from the south. Erosion of top sets in a more marginal setting is observed, along with deposition of basin floor fans at the toe of the prograding clinoforms. The overlying seals are basinal sediments as well as mudstones and siltstones of subsequent progradational sequences. Mild structural modification of potential stratigraphic traps in the Judd Basin occurred during the Oligo-Miocene inversion associated with continued opening of the North Atlantic. Drilling seismic amplitude anomalies in the West of Shetlands area has often been unsuccessful. Therefore, a fully integrated geophysical and geological evaluation was carried out on the T38 anomaly comprising rock physics, amplitude variation with offset analysis, fault seal analysis and the acquisition of a CSEM survey which, supported by a valid geologic model, have reduced the risk from high to moderate. The results indicate that the anomaly has the potential to be sand-bearing and contain oil and gas. It is proposed that an integrated evaluation can reduce the level of uncertainty associated with an anomaly much more effectively and so improve the chance of exploration success.

Abstract Fifty years after the discovery of the giant Groningen gas field, good insight into the remaining hydrocarbon exploration potential of the Netherlands is of great interest due to the aging infrastructure. In a review of prospective areas, the stratigraphic element of Dutch play areas has been summarized for conventional and unconventional formations. This is to answer the question of whether stratigraphic traps can contribute to future exploration. Complex faulting, very common in the Dutch subsurface, makes structural definition generally the highest prospect risk. With increase in 3D coverage over the country, many structures have now been drilled successfully. The success of structural traps has left the stratigraphic plays and prospects under-explored. Most hydrocarbon reserves in the Netherlands have been discovered in Permian Rotliegend and Triassic Bunter sandstone reservoirs, which are not prone to much stratigraphic trapping as a consequence of very gradual facies changes. Other prospective horizons and hydrocarbon reservoirs in the country range in age from Carboniferous to Cenozoic and can be found in clastic and carbonate rocks. They share an overall comparable basin setting but the varying interplay at basin margins creates varying stratigraphic elements. Rifting creates new facies variation during the Mesozoic. Salt movement is another factor that creates stratigraphic components in trapping. The various erosional events create other possibilities for stratigraphic trapping. This, combined with varying relative sea-levels through time, creates very distinct stratigraphic intervals often correlatable over large distances. The very limited contribution of stratigraphic traps to present-day gas finds may change in the future because of improved seismic. Risking of prospects needs better understanding of stratigraphic elements in various plays. This includes the stratigraphic aspects of reservoir sealing in dominantly structural traps and the nature of source horizons.

Abstract Laggan, located in the west of Shetland, was discovered in 1986. There is now an improved understanding of Laggan, thanks to innovative and fully integrated geoscience studies and a successful appraisal campaign. Development studies are well advanced, with the discovery of Tormore in 2007 providing the potential for a combined development project. Laggan and Tormore are Paleocene gas condensate discoveries in approximately 600 m water depth. The traps are both mixed, stratigraphic with updip closure against bounding faults. The reservoir comprises sand-rich turbidite channelized lobes and lobes. Reservoir properties are good (permeability range 30–300 mD) due to the presence of chlorite and pre-sorting on the shelf. The geoscience evaluation of Laggan has matured over the last four years with the help of fully integrated studies using 3D seismic and well data. The depositional model has been defined on the basis of an evaluation of cores and seismic and supported by analogue studies. Seismic inversion studies have also helped constrain the reservoir architecture. Of particular value has been the application of AVO to quantify net gas sand, recognized as the principal static uncertainty. The main dynamic uncertainty is the risk of compartmentalization. This risk has been reduced through an improved definition of the fault configuration by re-processing the seismic and detailed seismic attribute analysis. The potential of Tormore was recognized by applying the geoscience understanding of Laggan to help de-risk the prospect. In particular, it was recognized that Laggan could be used as an analogue for the Tormore trapping configuration and reservoir potential and that AVO could be used to help define the Gas–Water Contact. The exploration well, drilled in 2007, was successful in finding a similar reservoir to that encountered in Laggan. The fluid encountered was a gas condensate, approximately three times richer than Laggan.