Abstract The Eocene age Brimmond Sand Fairway is situated along the north-eastern flank of the Paleocene Forties Field (UKCNS blocks 21/10 and 22/6). Located along the western margin of this Brimmond Fairway are well imaged remobilized sands that form the reservoir interval for the Maule and Tonto Fields and, along with deep-water channels, the Brimmond Field. These Eocene Brimmond sandstones are encased in the Horda Shale which provides the sealing lithology. The interpretation of these remobilized and injected sands is driven from geometries derived from 3D seismic and historic logging of thin sandstones in the Eocene interval. Conical shape features with sills and steep dykes are mapped, with seismic evidence of injection along active faults and fractures. The developments of the Brimmond, Maule and Tonto Fields has been successful due to impressive seismic imaging with inversion and Direct Hydrocarbon Indicator (DHI) volumes allowing the identification of hydrocarbon bearing remobilized sandstones, along with 4D data imaging un-swept areas.

Abstract The Forties Field, discovered by BP in 1970, is the largest oilfield on the UK Continental Shelf. It is trapped in a simple four-way dip closure, with a Paleocene turbidite sandstone reservoir. The Forties Field originally contained between 4.2 and 5 billion bbl of oil, with 2.75 billion bbl produced to June 2017. Production has been supported by water injection and the influx of a regional aquifer. The original development contained equally spaced producers with peripheral injectors. As the field matured, production was concentrated in the crestal parts of the field with injectors tending to be moved upflank. With the development of seismic lithology prediction and fluid detection, together with 4D seismic technology, it became possible in the late 1990s to target bypassed oil in unexpected locations throughout the field. In 2003, BP sold the field to Apache who were able to rejuvenate production, adding over 170 MMbbl oil reserves, with an extended drilling campaign targeting bypassed pay identified using seismic technologies. Production at the Forties facility has been further enhanced by the development of four satellite oilfields, Bacchus (Jurassic reservoir), Brimmond, Maule and Tonto (Eocene reservoirs), together with Aviat (Pleistocene reservoir) produced for fuel gas supply.

Abstract The Ormen Lange Field is a gas reservoir offshore mid-Norway, developed in a combined structural–stratigraphic–hydrodynamic trap. The lobe-dominated turbidite deposits are mostly of excellent quality, but show a significant deterioration trend towards the fan fringe at its northern margin. Axial parts of the fan contain amalgamated sand-rich deposits, which pass laterally into layered sequences characterized by intercalation of low-permeability heterolithic drapes. Along its 40 km length, the field contains in excess of 400 linked polygonal faults attributed to de-watering of underlying shales. Despite pervasive faulting, reservoir connectivity on a geological timescale is proved by a common pressure gradient in pre-production wells and depletion seen in all later development wells. Recent appraisal drilling of the fan fringe, occupying the crest of the field, encountered only residual gas saturations, despite being located in an area delineated by a seismic direct hydrocarbon indicator. A hydrodynamic aquifer concept is the most plausible explanation for the fluid distribution, in which the gas from the crest of the structure is displaced, leaving behind a northward-thickening prism of residual gas. Dynamic simulation of the fluid-fill evolution over geological time showed the hydrodynamically tilted contact depends on rate of water flow across the aquifer, stratigraphic baffling and faulting, and reservoir quality, i.e. clean sand fraction and effective permeability. Optimal development of this deep-water reservoir depends on understanding the relationship between reservoir quality, connectivity, and the position of the free water level (FWL) in the field. A range of FWL in the north of the field, only weakly constrained by the wells, was empirically established from the hydrodynamically initialized models. This allowed a robust test of the production wells planned to drain the margin of the field. Modelled predictions of reservoir quality and pressures were confirmed by subsequent drilling.

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.

Abstract The Fram discovery, located in the UK Central North Sea, comprises the Paleocene-aged Forties Sandstone Member with an oil rim and primary gas-cap trapped within a four-way dip closure around a pierced salt diapir. The Forties Sandstone Member reservoir at Fram is characterized by very-fine- to fine-grained sandstones interbedded with shales with post-depositional small-scale slumping and sand injection, interpreted to be the product of high-density turbidity currents and debris flows. Deposition was in an overall distal and marginal, basin-floor lobe environment. The Forties reservoir interval is considered to comprise a series of offset-stacked, turbidite lobes characterized by a systematic variation from axial amalgamated sandstone facies to more distal, marginal and thinner-bedded heterolithic sandstone facies, producing an overall sheet-like reservoir architecture. The Forties reservoir at Fram is thinner and poorer when compared with more proximal parts of the Forties submarine fan system, and reservoir quality is strongly controlled by sedimentary facies. The architecture of the reservoir is expected to result in poorer vertical, but greater lateral, stratigraphic continuity when compared with more channelized Forties reservoirs such as the Nelson and Forties fields further to the north. A key step in understanding and characterizing the Fram reservoir was the appraisal drilling in 2009, which included coring, comprehensive wireline logging, formation pressure data acquisition and a drill stem production test. This paper provides an overview of the Fram reservoir geology and demonstrates how integration of data acquired in the 2009 29/3c-8,8z appraisal wells with 3D seismic datasets, existing E&A wells and analogues has helped to improve reservoir characterization and identify the major subsurface uncertainties needing to be addressed during the field-development planning.

Abstract The Volund Field lies in the Norwegian sector of the North Sea (Quad 24/9). This field produces from a ‘classic’ large-scale sandstone injection complex located in Lower Eocene strata. The sandstone reservoir has been injected into the lower permeability surrounding mudstones of the Sele and Balder formations and Hordaland Group to create an ‘intrusive trap’. The Volund Field consists of a deeper central unit of stacked sandstone sills, surrounded by shallower, steeper-dipping injected sandstone dykes, which make excellent reservoirs with consistently high porosity and permeability. Many of the steeply-dipping injected dykes appear to have excellent connectivity from the water leg through the oil leg and into the gas cap. The complex was identified on seismic data that exhibit a Class 3 amplitude versus offset (AVO) signature on the far-offset stack reflection seismic volume. The seismic data have been used to successfully locate horizontal production wells. Volund seismic geobodies have been extracted and incorporated into the reservoir geomodel to determine the geometry of the injectite features and to populate sands within the injection complex. Volund Field (estimated mean gross resource of 54 mmboe (million barrels oil equivalent)) is producing oil from four horizontal branches (end December 2012), with one water injector well, and has a common oil–water contact and gas–oil contact.

Abstract The Forties Field, the largest oilfield in the UK North Sea, has been a prolific producer since its initial development. With an initial plateau rate of 500 000 bopd the field had produced some 2500 mmbo and the field rate had declined to 41 000 bopd by 2003 when the operatorship changed from BP to Apache. From 2004 to 2012, over 100 bypassed pay targets were drilled with a success rate of 75%, establishing a late life plateau of 50 000–60 000 bopd. The Forties reservoir is provided by Paleocene turbidites of the Forties Sandstone Member of the Sele Formation, deposited in a channelized proximal area of the Forties Fan. In this paper, the reservoir architecture is described, and bypassed pay examples are discussed in the context of the reservoir architecture and the production history. Bypassed pay is shown to occur in both the high net to gross channel axes and the heterogeneous wing deposits. Oil is trapped by subseismic channel architecture and subtle faulting. The occurrence of bypassed pay at a particular location is also shown to be dependent on the continually evolving pattern of injection and production within the field.

Abstract As giant oil fields mature, the flow of results from development drilling and production history, as well as interpretations of new seismic data, provide an evolving view of in-place volumes, reservoir architecture and fluid movement through the reservoir. Often, such changes can trigger modifications to asset development plans and, together with economic conditions, revisions to estimates of ultimate recovery. The development of the Alba Field – a relatively heavy oil (19° API) accumulation lying in an Eocene deep-water channel complex in Block 16/26 of the UK's Central North Sea – has followed a similar pattern. With an estimated 900 mmbbl of oil in place, the reservoir is characterized by thick, high net-to-gross (NTG) sands with extremely favourable reservoir properties. Because of the less favourable mobility ratio, Alba has been developed exclusively by horizontal production wells, with pressure support provided by a series of seawater injectors. By mid-2012, after 18 years of production, more than 390 mmbbl of oil had been recovered. During production, several key seismic and drilling technologies were applied to address reservoir complexities and reservoir management concerns that emerged as field development progressed. The most significant of these include the following: a dramatic uplift in imaging the depositional architecture was provided by converted shear wave seismic data (1998), revealing an extremely irregular top reservoir and hinting at greater internal complexity than initially modelled; advances in extended reach drilling technology enabled a greater number of infill targets to be accessed, while geosteering techniques allowed better well placement, and horizontal completions using gravel packs improved well reliability; spectacular images of production cones beneath horizontal production wells extracted from a dedicated 4D monitor survey (2008) addressed the field's key dynamic uncertainty – where is the remaining oil? A challenge for Alba has been to fully understand a 4D seismic signal that originates from long horizontal producers where vertical rather than lateral sweep dominates. Ultimately, reliable reservoir models that capture these valuable dynamic insights, based on geologically reasonable interpretations, will be the key tool that enables bypassed oil to be targeted and recovered, as fields such as Alba advance towards their development vision.

Abstract The Gannet A Field is an Eocene-aged Tay Sandstone Member reservoir located in the Central North Sea, with a thin oil rim and overlying gas cap that was developed in the early 1990s. The field comprises a very high quality reservoir and is connected to a large and active aquifer. These two factors in combination have led to a highly dynamic system during production, with significant migration of fluids around the field as offtake evolved. A considerable amount of surveillance data, including time-lapse (4D) seismic data, oil geochemical sampling and cased-hole saturation logs, has been acquired that allows the fluid flow and contact movement within the reservoir to be tracked. Integration of the individual datasets has allowed the key controls on fluid flow in the reservoir to be determined. The depositional architecture has strongly influenced reservoir behaviour, with the positioning and geometry of the non-net facies being the primary control on fluid flow, water-cut development and fluid distributions throughout the field. This has been demonstrated through static and dynamic reservoir modelling and validation of the results with the surveillance data.

Abstract Discovery of the Arbroath, Montrose and Forties fields initiated intensive exploration of the Tertiary deep-marine play in the North Sea region. Subsequent discoveries demonstrated the success of this play and the geological diversity of the depositional systems. The play is now mature and in many areas the remaining exploration potential is likely to be dominated by small, subtle traps with a major component of stratigraphic trapping. Economically marginal discoveries need an in-depth understanding of subsurface uncertainty to mitigate risk with limited appraisal wells. Mature fields require detailed geological understanding in the search for the remaining oil. This volume focuses on the regional depositional setting of these deep-marine systems, providing a stratigraphic and palaeogeographical context for exploration, and development case histories that outline the challenges of producing from these reservoirs. The fields are arranged around the production life cycle, describing the changing needs of geological models as the flow of static and dynamic data refines geological understanding and defines the nature of new opportunities as fields mature.

Abstract Widely distributed deep-water fan sandstones of early Tertiary age form the reservoir for one of the most successful and prolific plays in the North Sea and NE Atlantic margin. Stratigraphic interpretation of a large well database provides the basis for mapping sand distribution and depositional environments in these two hydrocarbon provinces. Sand thickness maps for five Paleocene–Lower Eocene plays illustrate the intimate relationship between pre-existing structural features and sand distribution and facies in the North Sea. Large-scale depositional environment mapping gives an insight into the similarities and differences between basin evolution and sand distribution in North Sea and NE Atlantic margin basins. Both provinces were affected by the same succession of pre-break-up and syn-break-up tectonic and magmatic events that led to early Eocene continental separation and the formation of the NE Atlantic. The impact of these events was muted within the North Sea, which was protected from Paleocene rifting on the NE Atlantic margin by the Scotland–Shetland hinterland and from Paleocene–early Eocene volcanism by its more distant location. However, it was the combination of tectonic and thermal uplift of this clastic source area that contributed the large volumes of sand that accumulated in both these provinces.

Abstract This study presents an integrated seismic, well and core-based analysis of the Maureen Formation in the Central Graben of the North Sea. Facies analysis reveals that it is possible to divide the Maureen sandstones into amalgamated, sand- and mud-prone divisions, but that the related chalk facies are complex and imply a range of depositional processes including pelagic fallout, debris flows and turbidity currents. These chalk deposits have an impact on the interpretation of amplitude-based seismic attribute volumes. Detailed petrophysical mapping, supported by seismic analysis, reveals that the Maureen sandstones were deposited in distinct western and eastern fairways controlled by the relict Mesozoic rift topography (although offset stacking is an important intragraben process). The spatial extent of the Maureen sandstones is similar to the overlying Sele and Lista formations and suggests that the broad controls on sediment routing were the same throughout the Lower Palaeogene. Other similarities between these systems include the role of sandstone texture in controlling reservoir quality (although the heterolithic nature of the Maureen sandstones means that porosities and permeabilities are lower). A pattern of intraformational progradation and late-stage backstepping of the sandstone units is likely related to sea-level variability.

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 A seismic stratigraphic analysis constrained by well and wireline log data has been undertaken on the Paleocene and earliest Eocene succession of the South Buchan Graben (Quadrants 20 and 21), Outer Moray Firth Basin (OMFB). Two principal sequences have been described relating to two regressive/transgressive second-order cycles of relative sea-level change. The Maureen, Andrew, Glamis Tuff and Balmoral sandstone members are expressed as a stacked set of lowstand basin floor fans separated by mudstone intervals representing four cycles of third-order relative sea-level change. The Sele and Balder formations contain both basinal and shelfal packages as an expression of two cycles of third-order relative sea-level change. The Forties Sandstone Member is deposited within highly mounded, levee-confined channels downlapped by a prograding slope succession with well-defined clinoforms and deltaic topsets attributed to the Dornoch and Beauly formations. The individual parasequences of the prograding wedge are related to higher-order eustatic fluctuations with incision and slope fans, attributed to the Cromarty Sandstone Member, deposited during periods of relative sea-level lowstand. It is demonstrated that through the integration of lithostratigraphic, seismic geomorphological and sequence stratigraphic analyses an understanding of depositional environments and the distribution of facies within them can be obtained. The identification of basinal and slope features with reservoir potential, along with an understanding of their chronostratigraphic relationship to sealing facies, play an important role in regional play fairway mapping and risk analysis in this area and beyond. Future prospectivity within mature basins, such as the OMFB, relies on subtle stratigraphic traps typical of lowstand systems tracts, where the main risk is associated with reservoir quality and containment.

Abstract As hydrocarbon-prone basins mature through time, stratigraphic traps become increasingly important as hosts for yet-to-find reserves. Explorationists strive to reduce the uncertainty in reservoir distribution and quality, but considerable complications exist in the evaluation of stratigraphic traps owing to the inextricable links between stratigraphy, trap definition and their subsequent risking. This study quantifies the relationships that exist between reservoir geometries and the rates of reservoir property degradation in a turbidite sandstone pinch-out zone. The investigation focuses on the Paleocene Forties Sandstone Member of the Everest and Arran fields of the East Central Graben of the UK North Sea. We utilized standard seismic interpretation techniques and integrated stratigraphic and petrophysical analysis of wireline log data to map deep-water turbidite sandstone terminations and develop a predictive model for reservoir property changes close to the feather edge. The Forties Sandstone Member thins systematically up on to a palaeoramp on the eastern basin margin of the Central Graben. Results reveal that the net reservoir sandstones pinch out after the turbidite flows had traversed 5 km across the palaeoramp. The gross interval is predicted to completely terminate 6.4 km up the palaeoramp. The reservoir properties decrease in concert with the thinning trend in the wedge zone as a function of the interaction of palaeotopography and the hydraulics of the decelerating flows. The inclination of the counter-regional slope is considered to be a key controlling factor that determines the rate of thinning and thus the termination position of the sandstones and their concomitant reservoir property decline. The results of this study demonstrate that characterization of pinch-outs into distinct zones based on a palaeotopographic template can be of utility in stratigraphic and combination trap definition. This work also has wider implications for prospect risking, volumetric analysis, the population of properties and geological modelling of stratigraphic traps.

Abstract The Merganser Field is located in the East Central Graben of the UK Central North Sea, and consists of a gas/condensate column trapped in a structural attic on the flanks of a fully penetrating salt diapir. A large salt overhang obscures the field and structural definition is challenging owing to poor seismic imaging. Exploration drilling established a column of 1327 ft in Paleocene-aged deep-marine deposits of the Forties, Andrew and Maureen Sandstone members, and revealed significant geological complexity. Depositional styles record the relationship between salt tectonics and sedimentation, with variable reservoir distribution influenced by halo-kinetically induced palaeorelief and accommodation space. Re-mobilization of sediments is observed at multiple scales, and includes centimetre-scale de-watering structures, decimetre-scale sand injectites and kilometre-scale olistoliths. Whilst the hydrocarbon properties are consistent, contact depths are variable. Pressure data indicate compartmentalization across the field, which is likely to be caused by either radial faulting or hydrodynamic effects. Owing to the magnitude of subsurface uncertainty, the Merganser discovery could not sustain the investment required for standalone facilities. The development of the neighbouring Scoter Field provided the requisite local infrastructure to progress Merganser into production. The Field Development Plan (FDP) estimated recovery of 100 bscf gas and 3 mmstb condensate, and focused on delivering a low-cost development solution consisting of two horizontal wells and a subsea tie-back that would be robust against the downside, yet maintain flexibility to optimize in an upside outcome. Pilot holes were drilled to establish top reservoir with the subsequent horizontal well trajectories being re-designed to reflect structural geometry. The reservoir sections would maximize connectivity between fault compartments and stratigraphic units, and positioning was optimized with well-site biostratigraphy. Each reservoir section exceeds 4000 ft and maintains at least 1000 ft vertical stand-off from the gas/water contact. The facilities include a 5 km subsea tie back to the Scoter production manifold, with metering at the Merganser manifold for allocation purposes. Gas and condensate are commingled with Scoter, and transported 11 km to Shearwater for processing. The gas is transported onshore through the Shearwater Elgin Area Line and condensate through the Forties Pipeline System to Kinneil. Field performance to date has exceeded the FDP P50 both in terms of daily rate and cumulative production. Early production rates peaked at 100 mmscf/day of gas and 6000 stb/day of condensate and, to end-2014, Merganser has produced 161 bcf of gas and 10 mmstb condensate. This performance is due to a combination of better than expected connectivity, high reservoir k h , lower draw-down afforded by long horizontal wells and compression at the Shearwater platform. Subsurface uncertainties prior to development were considerable and the ‘appraisal through development’ strategy has demonstrated that success is achievable through meticulous planning and scenario analysis.

Abstract The Lochranza Field was developed using seismic amplitude analysis, evolving conceptual geological models and the implementation of horizontal well technology, built on the knowledge gained from the adjacent Donan Field redevelopment. Subtle depositional and structural complexities were, however, encountered in the Lochranza development wells. These had the potential to impact on the successful targeting of reservoir sands. Thinning sands and erratic lateral sand pinch-outs at the margins of the deep-water Balmoral Fan complex, small-scale sand injection and subtle structural complexity across the Lochranza Field were identified in the first phase of development. These introduced greater interpretation uncertainty and made further development challenging. This highlighted the importance of considering alternative geological scenarios, whilst these insights aided the identification of infill well opportunities. These uncertainties were partially mitigated by the planned development well trajectory, the data acquisition programme and the ability to geosteer based upon the geology encountered. It proved important to be mindful of different geological scenarios whilst geosteering, guided by the real-time dataset, keeping the 3D geological model peripheral to decision-making to limit the impact of anchoring bias. Identification of infill targets used a pragmatic approach based upon empirical data that showed that well recovery efficiency could be characterized by net pay length, stand-off from the oil–water contact (OWC) and connected hydrocarbon volume. Infill opportunities were defined probabilistically and subsequently supported by 3D reservoir simulation. This assessment was helped significantly by additional appraisal being undertaken as part of development well drilling.