Abstract The Paleocene–Eocene-aged Sele Formation is developed across the basinal region of the Central North Sea. The section comprises a number of deep-marine fan systems that expanded and contracted across the basin floor in response to relative sea-level changes on the basin margin and fluctuating sediment yield off the Scottish landmass modulated by climate and hinterland uplift. Persistent sediment entry points to the basin resulted in the development of discrete axial and transverse fan fairways with a geometry dictated by an irregular bathymetry sculpted by differential compaction across Mesozoic faults, halokinesis and antecedent fan systems. A high-resolution biostratigraphic framework has allowed the evolution of fan-dispersal systems in response to these effects to be tracked across the basin within four genetic sequences. The proximal parts of the fans comprised channel complexes of low sinuosity, high lateral offset, and low aggradation. The development of these systems in a bathymetrically confined corridor of the Central Graben ( c. 65 km wide), combined with high sediment supply, resulted in the eventual burial of any underlying relief. The behaviour of sand-rich reservoirs in this region is dominated by the permeability contrast between high-quality channel fairways and more heterolithic overbank regions, with the potential for early water breakthrough and aquifer coning in the channel fairways, and unswept volumes in overbank locations. Compartmentalization of compensationally stacked channel bodies occurs locally, with stratigraphic trapping caused by lateral channel pinch-outs, channel-base debrites, mud-rich drapes and abandonment fines. Towards the southern part of Quadrant 22, approximately 150 km down-palaeoflow, the systems became less confined and in this region are dominated by channel–lobe complexes, which continued to interact with an irregular bathymetry controlled by antecedent fans, mass-transport complexes and halokinesis in the form of rising salt diapirs. Reservoirs in this region are inherently stratigraphically compartmentalized by their heterolithic lithology and compensational stacking of lobes, and further complicated by structuration and instability induced by the diapiric or basement structures needed to generate a trapping structure in these settings.

Abstract Detrital garnet suites have been demonstrated to be reliable indicators of the mineralogical and lithological characteristics of sediment source areas. This study applies garnet analysis to the Paleocene to Eocene Sele Formation deep-water sandstone units of the central North Sea. These stratigraphic units are economically important as they represent one of the main hydrocarbon reservoir intervals in this mature basin. The routing of turbidity currents into the Central Graben has been demonstrated to be related to axial fans (ultimately sourced from Lewisian and Moine basement rocks and Triassic sandstones to the NW) and lateral fans (ultimately sourced from the Dalradian basement rocks to the west). Garnet analysis suggests the majority of samples can be attributed to the axial fan system and that the lateral system contributed little to sandstone deposition east of the Gannet Fields. This contradicts previous seismic mapping work, which suggested that the lateral fan system dominated sedimentation as far east as the Merganser Field. This reinterpretation is potentially important for our understanding of sediment routing and its impact on the distribution of reservoir quality, particularly as this is believed to relate directly to proximity to the shelf.

Abstract Turbidite reservoirs of the Sele Formation in the Central North Sea produce from fields such as Forties, Nelson, Montrose-Arbroath, Scoter, Pierce, the Gannet cluster, Guillemot A, Mirren and are under appraisal/development in fields such as Merganser, Phyllis, Starling and Blane. These reservoirs form part of the ‘Forties’ submarine fan system that was sourced from feeder channels in the northwest and west. Blanket 3D seismic coverage tied to wells shows that nearer their updip sources the turbidites are thicker, higher in net:gross, and more channelized. Downdip, the turbidite reservoirs are thinner bedded, finer grained and with depositional architectures that are characterized by stacked lobes and minor channels controlled by accommodation space and salt movement. In updip fields, such as Nelson and Forties, production is mature. High-quality reservoir channel sands are mostly drained. Recovery factors of 60–62% are achievable by application of water injection and 4D seismic technologies. The remaining challenge in these reservoirs is to (1) find by-passed oil in the channel facies and (2) to identify/model oil remaining in non-channelized facies, such as channel margin and interchannel facies. Portions of the channelized reservoirs have not been swept because of non-uniform water ascent and breakthrough or shale barriers. Non-channelized reservoirs have not been swept because their sands are thin bedded, interbedded with shales and of lower reservoir quality. Remaining oil zones are not correlatable between existing wells, emphasizing the uncertainties of lateral heterogeneities away from the wellbore and the importance of static reservoir modelling techniques to properly model, identify and plan infill targets with multiple realizations. Higher recovery factors (possibly as high as 70%) may be achievable with higher resolution seismic interpretations and reservoir models, application of enhanced oil recovery and sharpshooter drilling techniques and improved water management. In downdip fields, such as Scoter, Merganser, Pierce and Guillemot A, production is not as mature and wells are not as abundant. Consequently, development planning is more dependent on high-quality static and dynamic reservoir models to predict the interwell reservoir character, volumetrics and performance. In general, turbidite reservoir sandstones are thinner and finer grained. The thickest sands may be more correlatable as lobes/sheets. Permeability is lower than in updip reservoirs of equivalent porosity (tens of mD as opposed to hundreds or thousands of mD), probably due to reductions in mean grain size and textural maturity and a corresponding increase in detrital clay matrix. The greatest challenges lie in modelling lateral changes in net:gross, bed thickness, facies (especially shale bed architecture) and cementation. Where depositional slopes were oversteepened by the growth of salt diapirs, slumps and slides introduce lateral heterogeneities and reduce predictability in the reservoir section. Multiple faults radiate from such salt diapirs and may compartmentalize the reservoir. These effects may be mitigated by the construction of robust conceptual models of reservoir accumulation and architecture, supported by relevant field analogues and detailed biostratigraphy which may delineate multiple widespread marker horizons. For liquid hydrocarbons, recovery factors are typically 40–45%. Gas recovery factors are projected to be 60–65%.

Abstract Quad 29 in the Central North Sea is a focus for bp, with a strategy to identify remaining hydrocarbon accumulations to tieback to existing infrastructure. Capercaillie was appraised in 2017 with well 29/04e-5 and sidetrack 29/04e-5z. A gas cap and thin oil rim were intersected within the siliciclastic Paleocene–Eocene Sele Formation. The reservoir sandstones were deposited in a deep marine setting by sediment-gravity flow processes. Within the context of a relatively detailed knowledge of the surrounding area, the reservoir data-operational risk-cost balance was addressed through acquisition of a full wireline logging suite, pressure data, latest-generation microresistivity images and targeted large-volume rotary sidewall cores (RSWCs), with the latter two favoured over whole core. Mature deepwater descriptive schemes were applied at the sidewall core (lithotype), bed (borehole image facies) and bed-stack (depositional package) scales. This hierarchical approach provided robust sedimentological data to underpin higher-order depositional models, which together were used as a framework to (1) constrain the reservoirs’ mineralogical and textural attributes, (2) establish the main controls on rock quality and (3) explain the resulting variations in porosity and permeability. This study demonstrates that the careful integration of data derived from the latest borehole imaging tools and large-volume RSWCs can be a successful means of characterizing reservoirs from a sedimentological, reservoir quality and reservoir architecture perspective in mature basins. Similar approaches to geological reservoir characterization in such settings are likely to be a common cornerstone of cost-effective development during the energy transition.

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

Abstract The Paleocene-Eocene boundary is well defined in many areas of the North Sea Basin, often corresponding to (or close to) a signi?cant lithostratigraphic boundary. In the North Sea, this boundary is within the Sele Formation (in UK usage) and the Dornoch Formation. The entire Dornoch Formation is included in this chapter for convenience (Fig. 71). In onshore areas of the southern North Sea Basin (including the Paris Basin), the lower limit for the purpose of this chapter is at the base of the Tienen Formation (Belgium) and the Mont Bernon Group (Paris Basin). This is a close approximation to the Paleocene-Eocene boundary.

Abstract The Andrew and Cyrus fields lie in UK Blocks 16/27a and 16/28 at the junction of the Witch Ground Graben and the South Viking Graben. The Andrew Fields was discovered in 1974 with well 16/28-1, and Cyrus in 1979 with well 16/28-4. Both fields share a common reservoir the Paleocene Andrew Formation and both are sealed by the overlying Andrew Shale and Sele Formation. Similarly the traps for both fields formed above swells within Zechstein salt. The Andrew and Cyrus Fields differ in their petroleum content. Andrew contains both gas and oil (40API) while Cyrus contains only oil (30API). Reserves for the Andrew Field are 140MMBBL based upon a 46% recovery factor using natural aquifer drive. The same mechanism will deliver 16.5MMBBL from Cyrus at a 21 % recovery factor. Production began from Andrew in July 1996. Cyrus production began in April 1990 using the SWOPS system until April 1992. The small field was subsequently tied back to Andrew.

Abstract The Marathon-operated West Brae Field straddles Blocks 16/06a and 16/07a in the UK Central North Sea approximately 140 miles (225 km) NE of Aberdeen. The field was discovered in 1975 with drilling of exploration well 16/07-2. The West Brae reservoirs consist of Eocene Balder Formation and Upper Sele Formation Sandstones that were deposited in NW-SE trending submarine channels across the area. Development of the field commenced in April 1997 with first oil being achieved in October the same year. The field has been developed using sub-sea tie-back to the Brae A platform, which lies 5.6 miles (9 km) SE of the sub-sea manifold. Recoverable reserves are estimated to be 60 MMBBLs, of which some 23 MMBBLs had been produced by 31 December 1999.

Abstract The MacCulloch Field lies within Block 15/24b in the UK Central North Sea and is located on the northern flank of the Witch Ground Graben. It was discovered by Conoco well 15/24b-3 in 1990. MacCulloch Field is a four-way dip closure at Top Paleocene over a deeper Mesozoic structure. The reservoir consists of Upper Balmoral Sandstones containing 32-37° API oils derived from Kimmeridge Clay Formation shales and sealed by shales belonging to the Sele Formation. The field contains recoverable reserves of 60-90 MMBOE. Reservoir quality is generally very good, with an average porosity of 28% and core permeabilities (Kh) between 200 mD and 2D. AVO anomalies and a seismic flat spot are associated with oil filled reservoir and the oil-water contact in certain areas of the field.

Abstract The Blane Field is located in the central North Sea in Block 30/3a (Licence P.111), approximately 130 km SE of the Forties Field, in a water depth of 75 m (246 ft). It straddles the UK/Norway median line with 82% of the field in the UK and 18% in Norway. Blane produces undersaturated oil from the Upper Forties Sandstone Member of the Sele Formation and contains good quality light oil within a four-way structural closure; it has a hydrodynamically tilted original oil–water contact. The field stock-tank oil initially in place estimate is 93 MMbbl with an expected ultimate recovery of 33 MMbbl. Blane first oil was achieved in September 2007. The field has been developed by two horizontal producers located on the central crest of the field supported by a water injector drilled on the NW flank. Oil production peaked at c. 17 000 bopd in 2007 and the field is currently in decline. By the end of 2018 production was c. 3000 bopd with 55% water-cut. Cumulative oil production to the end of 2018 was 26.6 MMbbl.

Abstract The Huntington Oil Field is located in Block 22/14b in the Central Graben of the UK Continental Shelf. The reservoir is the Forties Sandstone Member of the Sele Formation, and oil production is from four production wells supported by two water-injection wells, tied back to the Sevan Voyageur FPSO (floating production storage and offloading unit). Initial estimates of oil-in-place were c. 70 MMbbl and the recovery factor at the end of 2017 after 4.5 years of production was 28%, which reflects the weak aquifer and poor pressure support from water injection. The Huntington reservoir is part of a lobate sheet sand system, where low-concentration turbidite sands and linked debrites are preserved between thin mudstones of regional extent. Within the reservoir, three of the thicker mudstone beds can be correlated biostratigraphically on a regional basis. This stacked lobate part of the system sits above a large-scale deep-water Forties channel that is backfilled by a system of vertically aggrading channel storeys. Despite the relatively high net/gross of the reservoir, the thin but laterally extensive mudstones in the upper (lobate) part of the system are effective aquitards and barriers to pressure support from water.

Abstract Lomond is a gas–condensate field on the east flank of the Central Graben UK Continental Shelf, some 230 km east of Aberdeen in Block 23/21. The field was discovered in 1972 and was developed with nine production wells from an integrated production platform. Lomond is a large salt-induced anticline with four-way dip closure. The reservoir comprises Paleocene turbidite sandstones with the majority of the hydrocarbon volume in the Forties Sandstone Member and the top seal is provided by laterally extensive mudstones of the Sele Formation. The field is structurally compartmentalized with three different hydrocarbon–water contacts, but with the gas leg in pressure communication. Significant reservoir and structural complexities are observed in Lomond Field; however, the production behaviour exhibits classical tank-like depletion behaviour over its production history. With a very high recovery factor to date, the field has produced 883 bcf or 86% of the gas resource initially in place.

Abstract The Enoch Field is located in the South Viking Graben and straddles the UK/Norway median line with 80% of the field in the UK and 20% in Norway. Enoch produces undersaturated oil from the Early Eocene-age Flugga Sandstone Member of the Sele Formation. Hydrocarbons have been trapped by a combination of compaction-related dip closure and sand pinchout. The current stock tank oil initially in place estimate is c. 42 MMbbl with expected ultimate recovery of 11.5 MMbbl. The field was brought onstream in May 2007 via a single horizontal subsea gas-lifted well tied back to the Brae Alpha platform. Initial oil production rates were c. 11 800 bopd. The field is currently in decline and in December 2018 production was c. 1800 bopd with 80% water-cut. Cumulative oil production to the end of 2018 was 10.581 MMbbl.

Abstract The Arran Field contains gas-condensate accumulated within the Paleocene Forties Sandstone Member of the Sele Formation. It is located along the margin of the medial Forties turbidite depositional system, on the eastern flank of the Central Graben's Eastern Trough. The field comprises a low-relief southern extension (Arran South) from a high-relief northern closure (Arran North) around a salt diapir. The eastern margin of the field represents the pinch-out of the Forties Sandstone Member against the Jaeren High. As part of the field development planning, a comprehensive re-evaluation of subsurface data was undertaken. A thorough understanding of the reservoir distribution and turbidite architectures was vital to ensure that the appropriate elements were captured within the reservoir model. This was achieved through a thorough integration and multidisciplinary interpretation of all available data including seismic, core, petrophysical and analogue data. These data indicate that the best quality Forties Sandstone Member reservoir consists of stacked, elongate, amalgamated and non-amalgamated fairway sandstone bodies. These thick-bedded and sand-dominated reservoir units pass laterally into, and are extensively interbedded with, linked debrites, heterolithic low-density turbidite lobe fringe deposits, slumps, and debris flows, along with hemipelagic and turbiditic shales. A seismic shale volume ( V shale ), derived from inverted pre-SDM data, together with reflection seismic data, were used to identify and map intra-reservoir depositional lobe geometries. These show large-scale, lobe-like depositional bodies which migrated laterally over time and onlapped on to the Jaeren High to the east. Within these, smaller-scale elongated lobe bodies, generally derived from the NW, are interpreted from layer-parallel extractions of the seismic V shale volume. Possible slump units were also identified, predominantly derived from the edges of the Arran North salt diapir, suggesting that the basin floor topography was mobile during deposition. The seismic V shale volume was used to condition the static facies model, utilizing probability relationships between the seismic data and core facies at the wells, providing a soft linkage between the data and models developed. Core, analogue data and facies interpretations from the seismic data were utilized to ensure that appropriate reservoir body geometries and spatial relationships were maintained in the static model and allowed key reservoir heterogeneities to be captured. This integrated approach also supported analysis of reservoir uncertainties, with specific focus on the vertical and lateral reservoir connectivity within this lobe-dominated reservoir.