About this title ‐ Petroleum Geology of NW Europe: 50 Years of Learning – Proceedings of the 8th Petroleum Geology Conference

The 8th Conference on the Petroleum Geology of NW Europe was held in September 2015 and marked the 50th anniversary of the first commercial discovery offshore in the North Sea (West Sole, in September 1965). Its focus was ‘50 Years of Learning – a Platform for Present Value and Future Success’ and its objective was to provide an update on discoveries, developments, technologies and geological concepts from the region.The 39 extensively illustrated technical papers cover the full width of recent activity and are divided into the following sections: Plays and fairwaysPlay assessmentRecent successes and learnings from failuresInfrastructure-led exploration and developmentLate-life fields, re-development and the ‘next life’Onshore exploration and development.The proceedings volume follows the format of many of the previous conferences since the first in 1974. Collectively these provide a unique documentation of the discovery and development of several NW European hydrocarbon provinces.The volume will be of interest to all geoscientists involved in exploration and development in NW Europe. It provides a fascinating overview of how creativity can continue to reveal hidden resources in an area that has been called ‘mature’ for at least the last 20 of its 50-year history.

The Beryl Field area: increasing production in a mature asset

The Beryl Field is one of the largest oil fields in the UK Continental Shelf. Mobil commenced production in 1976 via the Beryl Alpha platform. Production peaked at approximately 200 000 BOE/day in 1993 before declining to around 50 000 BOE/day in 2012.Apache assumed operatorship in 2012 and, along with partners Shell, has arrested and reversed production decline on platform production through investment in 3D seismic data, drilling, workovers and improvements to operational efficiency. Redevelopment to date by the Beryl area partnership has focused on strategic wells across multiple play types and fields. These wells have realized an 88% success rate and have led to the delineation of additional, lower risk, drill locations. Drilling flexibility, a deep target inventory and effective partner relationships help to expedite the most valuable opportunities and maintain the drilling campaign.In the future, production growth is anticipated through cost-effective developments of new and existing near-field opportunities, including the recently discovered Callater Field with first oil planned in 2017.Three case studies will illustrate: the importance of structural compartmentalization in under-developed fields; the opportunities remaining in mature fields as a result of historical field management practices; and the value of near and new field opportunities for extending field life.

The Shearwater Field – understanding the overburden above a geologically complex and pressure-depleted high-pressure and high-temperature field

The Shearwater Field, located in Block 22/30b in the UK Central Graben, remains one of the best-known fields in the UK Continental Shelf (UKCS). At the time of the initial development, Shearwater represented one of the most complex and technically challenging high-pressure and high-temperature (HPHT) developments of its kind in the North Sea. During the early life of the field, pressure depletion resulted in compaction of the Fulmar reservoir, leading to mechanical failure of the development wells. The compaction also resulted in weakening of the overburden due to an effect known as stress arching. Over time, this resulted in in situ stress changes in the overburden which have been observed from 4D seismic datasets and are in line with geomechanical modelling. This is particularly true for the Hod Formation in the Chalk Group, and resulted in the need to make changes to infill well design, including the use of new drilling technologies, to ensure safe and effective well delivery. The insights presented here, which relate to the understanding of pore pressure and fluid fill in the overburden, and how the overburden has responded to stress changes over time, are of relevance to current and future HPHT field developments in both the UK North Sea and elsewhere.

Unlocking 4D seismic technology to maximize recovery from the pre-salt Rotliegend gas fields of the Southern North Sea

The Southern North Sea is a mature gas basin, producing mainly from faulted Permian Rotliegend sandstones. Identifying infill well opportunities in un-depleted or partially depleted blocks in these fields is challenging, particularly if the sealing capacity of faults within a field is uncertain. Time-lapse (4D) seismic monitoring provides an opportunity to identify depleted reservoir blocks by measuring differences in travel time across the producing interval between seismic surveys acquired before and after gas production. 4D seismic field tests were initially performed by Nederlandse Aardolie Maatschappij (NAM) and Shell in 2001. However, the observed travel-time differences proved to be smaller than predicted and any possible signals were too noisy to confidently detect depletion. Since then, advances in seismic acquisition and processing technology have improved the accuracy of 4D measurements and enabled the effective mapping of 4D related gas depletion signals. 4D seismic has now been deployed over a number of fields in the Southern North Sea, and a portfolio of infill opportunities has been identified. In 2015, the first 4D targeted infill well was successfully drilled into a block with limited depletion. This technology represents a breakthrough for operators seeking to maximize hydrocarbon recovery and extend field life in the Rotliegend play of the Southern North Sea.

Regional study of controls on reservoir quality in the Triassic Skagerrak Formation of the Central North Sea

An improved understanding of the controls on reservoir quality is key to ongoing and future exploration of the Central North Sea Triassic play. This paper presents a regional integrated study of 50 000 ft of wireline log data, 10 000 ft of core, 4431 routine core analyses measurements and 377 thin sections from 86 cored wells.Triassic Skagerrak Formation sandstones represent thin-bedded heterogeneous reservoirs deposited in a dryland fluvial–lacustrine setting. Fluvial-channel facies are typically fine–medium grained and characterized by a low clay content, whilst lake-margin terminal splay facies are finer grained, more argillaceous and micaceous. Lacustrine intervals are mud-dominated. Primary depositional textures retain a primary control on porosity evolution through burial. Optimal reservoir quality occurs in aerially and stratigraphically restricted fluvial-channel tracts on the Drake, Greater Marnock, Puffin and Gannet terraces, and the J-Ridge area. These primary textural and compositional controls are overprinted by mechanical compaction, the development of early overpressure and diagenesis. Anomalously high porosities are retained at depth in fluvial sandstones that have a low degree of compaction and cementation, including chlorite. Forward modelling of reservoir quality using Touchstone™ software has been validated using well UK 30/8-3 where reservoir depths are >16 000 ft TVDSS (true vertical depth subsea).

Controls on the reservoir quality of Late Cretaceous Springar Formation deep-water fan systems in the Vøring Basin

A new reservoir quality model is proposed for the Late Cretaceous Springar Formation sandstones of the Vøring Basin. Instead of a depth-related compactional control on reservoir quality, distinct high- and low-permeability trends are observed. Fan sequences which sit on the high-permeability trend are characterized by coarse-grained facies with a low matrix clay content. These facies represent the highest energy sandy turbidite facies within the depositional system, and were deposited in channelized or proximal lobe settings. Fan sequences on the low-permeability trend are characterized by their finer grain size and the presence of detrital clay, which has been diagenetically altered to a highly microporous, illitic, pore-filling clay. These fan sequences are interpreted to have been deposited in proximal–distal lobe environments. Original depositional facies determines the sorting, grain size and detrital clay content, and is the fundamental control on reservoir quality, as the illitization of detrital clay is the main mechanism for reductions in permeability. Core-scale depositional facies were linked to seismic-scale fan elements in order to better predict porosity and permeability within each fan system, allowing calibrated risking and ranking of prospects within the Springar Formation play.

New insights into the unexploited reservoir potential of the Mid North Sea High (UKCS quadrants 35–38 and 41–43): a newly described intra-Zechstein sulphate–carbonate platform complex

The Mid North Sea High (MNSH) is located on the UKCS in quadrants 35–38 and 41–43. It is a large structural high that is flanked by the mature hydrocarbon provinces of the Central North Sea (CNS) to the NE and the Southern North Sea (SNS) to the SE. In the MNSH region, the source and reservoir intervals that characterize the SNS (Westphalian, Lower Permian) are absent and therefore the area is relatively underexplored compared to the SNS Basin (c. one well per 1000 km2). Nevertheless, two discoveries in Dinantian reservoirs (Breagh and Crosgan) prove that a working petroleum system is present, potentially charged either via lateral migration from the SNS or from within the lower Carboniferous itself. Additionally, gas was found in the Z2 carbonate (lower Zechstein Group) in Crosgan, with numerous other wells in the area reporting hydrocarbon shows in this unit. The results of the interpretation of recently acquired 2D and 3D seismic reflection datasets over parts of UKCS quadrants 36, 37 and 42 are presented and provide insight into both the geology and prospectivity of this frontier area.This study suggests that intra-Zechstein clinoform foresets represent an attractive, hitherto overlooked, exploration target. The Zechstein Group sits on a major unconformity, probably reflecting Variscan-related inversion and structural uplift. Below it, fault blocks and faulted folds occur, containing pre-Westphalian Carboniferous and Devonian sediments, both of which contain potential reservoirs. In the lower Zechstein, a large build-up is observed, covering a total area of 2284 km2. This is bounded on its margins by seismically defined clinoforms, with maximum thicknesses of 0.12 s two-way time (c. 240–330 m). This rigid, near-tabular unit is clearly distinguished from the overlying deformed upper Zechstein evaporites. In map-view, a series of embayments and promontories are observed at the build-up margins. Borehole data and comparisons with nearby discoveries (e.g. Crosgan) suggest this build-up to represent a Z1–Z2 sulphate–carbonate platform, capped by a minor Z3 carbonate platform. Interpreted smaller pinnacle build-ups are observed away from the main bank. The seismic character, geometry, size and inferred composition of this newly described Zechstein platform are similar to those of platforms hosting notable hydrocarbon discoveries in other parts of the Southern Permian Basin. The closest of these discoveries to the study area is Crosgan, which is characterized by the Z2 carbonate clinothem (Hauptdolomit Formation) as a proven reservoir.

Future directions in reservoir modelling: new tools and ‘fit-for-purpose’ workflows

Reservoir modelling tools can be invaluable for integrating knowledge and for supporting strategic oil field decisions. The pertinent issue is the capability of the modelling toolbox to achieve the required support: does modelling generate insights into the characterization of the subsurface, does it increase or decrease our working efficiency and does it help or hinder us in decision-making? In this respect, we see two directions emerging in reservoir modelling and simulation. One surrounds software technology development and a move towards a grid-independent world. This is a current research issue but some of the components required to complete a new workflow are already in place and tools for certain specific applications may not be far away. The other involves a change in approach to model design. This involves a move away from big, detailed ‘life-cycle’ models to more nimble workflows involving multi-models (either multi-scale or multi-concept) which may or not include full-field modelling exercises. A distinction between ‘resource models’ and ‘decision models’ helps crystallize this, is a positive step towards achieving ‘fit-for-purpose’ models, and is a change of model design strategy which can be achieved immediately.

Regional distribution and controls on the development of post-rift turbidite systems: insights from the Paleocene of the eastern North Viking Graben, offshore Norway

Paleocene deep-water deposits of the Norwegian sector of the North Sea Basin are prospective for oil and gas, although little is known about their sedimentology and distribution, or the controls on their stratigraphic evolution. To help unlock the potential of this poorly explored interval, we integrate 3D seismic reflection, well logs and core data from the eastern North Viking Graben, offshore Norway. We show that thick (up to 80 m), high net to gross (N:G) (up to 90%), sandstone-rich channel-fills and sheet-like, likely lobe deposits occur on the slope–proximal basin floor, forming part of an aerially extensive fan system. Sediment dispersal and the resultant stratigraphic architecture are controlled by slope morphology. Bypass occurred on the northern, passive margin-type slope; whereas, in the south, sediment gravity currents were deflected around, and deep-water sandstones onlap and pinch-out onto an exposed rift-related fault block that generated intra-basin bathymetric relief. Pinchout of deep-water sandstone into mudstone suggests that future exploration should focus on identifying subtle stratigraphic traps on fault block flanks or at the fan fringe. This trapping style contrasts with that encountered in the UK sector of the Northern North Sea, where most Paleocene fields and discoveries are in structural traps related to the flow of Zechstein Supergroup salt.