Turbidite reservoirs of the Sele Formation, Central North Sea: geological challenges for improving production

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%.

Character and distribution of hybrid sediment gravity flow deposits from the outer Forties Fan, Palaeocene Central North Sea, UKCS

“…Complex bed-scale juxtaposition of clean (reservoir) and remobilised muddy sandstone facies (non-reservoir) in the outer Forties Fan succession have been recognised in earlier studies, and attributed both to sand injection processes (Anderton, 1995) and to local secondary remobilisation, related spatially to coeval salt diapirism and sea floor deformation (Hempton et al, 2005). The outer Forties Fan system extended distally over an area of active salt diapirs, and many of the Forties hydrocarbon fields are in diapirrelated traps (Davidson et al, 2000).…”

“…The Lisa Formation below the Sele Formation was Mudge and Jones (2004). (B) 'T' sequence Maximum Flooding surfaces, after Hempton et al (2005) modified to produce regional correlation scheme between Pierce and Everest fields. (C) Proprietary field specific biostratigraphic scheme used to subdivide the FSM within the Everest field this has been modified to roughly show the regional seismic derived sequence stratigraphic scheme.…”

“…Almost 1060 m of released subsurface core and matching wireline logs from hydrocarbon fields located along the medial lateral and distal lateral eastern margin of the Forties Fan have been examined. The eastern fan margin was chosen as the focus of the study as the western part of the fan system is complicated by the Hempton et al, 2005) showing the main Forties Fan and lateral fans sourced from the west. Some of key hydrocarbon fields in the fan system are shown, including Everest Lomond and Pierce on the eastern margin of the fan that are the subject of this study.…”

Tertiary deep-marine reservoirs of the North Sea region: an introduction

“…Eldrett et al (2015) use a refined biostratigraphic framework of the overlying Sele Formation to map in detail the distribution and evolution of the component fan systems, providing insights into the reservoir distribution of this key interval as it responded to changes in sediment yield, progressive infilling of the post-rift basin floor and the impact of rising diapirs of Zechstein halite. These diapirs deformed the seafloor, resulting in bathymetric highs, local slumping, and deflection of sediment gravity flows (Davison 2004;Hempton et al 2005). Ongoing movement subsequently deformed these deposits, inducing steep dips, overturned stratigraphy, injection and faulting (e.g.…”

“…Parker 1975;Ahmadi et al 2003;Hempton et al 2005) and documented field case histories (cf. Abbots 1991;Gluyas & Hichens 2003).…”