This study delivers a refined, hierarchical deepwater reservoir characterisation scheme that significantly mitigates sub-surface drilling risk by systematically linking pore-scale flow heterogeneities to field-scale reservoir architecture. By standardising the descriptive and interpretive workflows across multiple data scales, the project successfully differentiated high-quality channel-fill sandstones (up to 445 mD mean permeability) from low-permeability terminal lobe deposits (1.2 mD). This approach provided greater certainty in reserve estimation and optimises well placement within a complex deepwater systems.
This study was performed in conjunction with bp. We are grateful to bp for authorising the publication of this study.
Neal, A., James, A., Payne, D., Ashton, M., van den Beukel, N. and Storer, D., 2023. Integrated borehole image and rotary sidewall core data to support infrastructure-led appraisal: Capercaillie Field, Central North Sea. https://doi.org/10.1144/SP527-2022-184
In Neal, A., Ashton, M., Williams, L.S., Dee, S.J., Dodd, T.J.H. and Marshall, J.D. eds., 2023, November. Core values: the role of core in twenty-first century reservoir characterization. Geological Society of London. https://doi.org/10.1144/sp527-2022-184
The Capercaillie field, situated down-dip in the mature Central North Sea, presents a significant commercial challenge: identifying and accurately modelling small, lower net-to-gross hydrocarbon accumulations within the deepwater Palaeocene-Eocene Sele Formation. The core risk lay in the high uncertainty associated with rock quality heterogeneity; average sandstone permeabilities were known to be low (a few 10s mD), but the geological controls on reservoir grade were poorly understood.
The primary objective (Aims) was to use an integrated, multi-scale dataset to accurately define the sedimentological architecture and petrophysical controls on reservoir quality. This systematic de-risking would enable the commercial viability of a potential tie-back to existing infrastructure by providing a reliable basis for volumetric estimation and sweep efficiency modelling.
The study was founded on a cost-effective, multi-scale database from two wells, 29/04e-5 (vertical) and the deviated sidetrack 29/04e-5z, which are laterally separated by approximately 1850m at reservoir depth.
The data suite comprised a full wireline log suite, pressure data, alongside
A hierarchical approach provided the framework to integrate these datasets:
Core-to-Log Link: Lithotypes (from RSWCs) and Image Facies (from BHI) were consistently applied to define bed/sub-bed scale depositional dynamics. The RSWCs themselves served as the direct source for Routine Core Analysis (RCA) data and fully quantitative petrographic analysis.
Upscaling: The bed-scale descriptions were grouped into log-scale Depositional Packages to model the vertical reservoir quality organisation.
This methodology ensured that precise physical measurements (from the RSWCs) were accurately anchored to the continuous geological context (from the BHI logs), despite an inherent RSWC-to-image depth match accuracy of only +/- 0.5m.
The effective systematic upscaling and coding of all available data (core and logs) enabled clear geological and reservoir quality separation between the stratigraphic units, fundamentally altering the understanding of the asset:
1. High-Value Channel-Fill Pay (S2b and S1b Upper):
2. Lower-Value Lobe Deposits (S1b Lower):
Figure 2 Schematic diagram showing the depositional model proposed by Davis et al. (2009) for the Sele Formation sediment-gravity flows in the Everest, Lomond and Pierce fields, Central North Sea. Using the bed type distribution proposed by Davis et al. (2009), this model has been overlaid with its equivalent depositional package distribution; and gross depositional maps for the S1 and S2/S3 units of the Sele Formation, Central North Sea, indicating the location of the Capercaillie Field. Source: modified from Eldrett et al. (2015).
The successful integration of BHI and targeted large-volume RSWCs has provided a robust, data-driven understanding of the Sele Formation, which has directly informed capital allocation. The study confirms that reservoir development should focus on the high-quality channel-fill sandstones of Units S2b and S1b Upper. The distinct petrographic and depositional models are now available to refine the definition of recoverable hydrocarbon ranges for different development cases. The immediate next step is to apply the validated hierarchical framework with their associated statistics to the static reservoir model to precisely quantify reserves and de-risk the tie-back of the channel targets (S2b, S1b Upper) to the existing infrastructure, thereby ensuring maximum cost-effectiveness during the energy transition.
