bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Huntington Field, Block 22/14a, UK North Sea
Authors: Couch Andrew G. , Eatwell Samantha , Daini Olu 
Published: October 2020

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.
The Rosebank Field, Blocks 213/27a, 213/26b, 205/1a and 205/2a, UK Atlantic Margin
Authors: Duncan Louise J. , Dennehy C. J. , Ablard P. M. , Wallis D. W. 
Published: October 2020

Abstract

The Rosebank Field is located primarily in Block 213/27a in the Faroe–Shetland Basin,
c.
130 km west of the Shetland Islands in water depths of
c.
1100 m (3600 ft). Hydrocarbons are trapped within an elongate, SW–NE-trending four-way anticlinal structure. The principal Colsay Sandstone Member reservoir consists of several vertically stacked, Late Paleocene to Early Eocene fluvial and deltaic reservoirs separated by volcanic sequences. Well log and core data indicate that reservoir quality is high, with porosities in the range of 19–23% and average permeability of
c.
3 D. Oil quality is also high, with average oil gravity of 37°API and
in-situ
viscosity of
c.
1 cP at a mean reservoir temperature of 175°F. The field holds a substantial resource and is currently under evaluation for development.
The Machar Field, Block 23/26a, UK North Sea
Authors: Sayer Zoë , Edet Jonathan , Gooder Rob , Love Alexandra 
Published: October 2020

Abstract
Machar is one of several diapir fields located in the Eastern Trough of the UK Central North Sea. It contains light oil in fractured Cretaceous–Danian chalk and Paleocene sandstones draped over and around a tall, steeply-dipping salt diapir that had expressed seafloor relief during chalk deposition. The reservoir geology represents a complex interplay of sedimentology and evolving structure, with slope-related redeposition of both the chalk and sandstone reservoirs affecting distribution and reservoir quality. The best reservoir quality occurs in resedimented chalk (debris flows) and high-density turbidite sandstones. Mapping and characterizing the different facies present has been key to reservoir understanding.
The field has been developed by water injection, with conventional sweep in the sandstones and imbibition drive in the chalk. Although the chalk has high matrix microporosity, permeability is typically less than 2 mD, and fractures are essential for achieving high flow rates; test permeabilities can be up to 1500 mD. The next phase of development is blowdown, where water injection is stopped and the field allowed to depressurize. This commenced in February 2018.
The Alba Field, Block 16/26a, UK North Sea
Authors: Moore Ian , Archer James , Peavot David 
Published: October 2020

Abstract
The Alba Field is a relatively heavy oil accumulation lying in an Eocene deep-water channel complex in Block 16/26a of the Central North Sea. With an estimated 880 MMbbl in place, the reservoir is characterized by thick, high net/gross sands with excellent reservoir properties and rock physics favourable for seismic property detection. The field has been developed by horizontal production wells, with pressure support provided by seawater injectors. After 24 years of production, more than 427 MMbbl have been recovered.
Over the course of the development, the results of development drilling and improved reservoir imaging from seismic have revealed greater reservoir complexity than anticipated at sanction. The highly irregular reservoir geometry is likely to reflect the internal stacking patterns of channel elements within the channel complex that are locally overprinted by post-depositional remobilization. This increased reservoir complexity has required more wells to effectively drain the expected volumes. Despite this, recovery has exceeded estimates from the initial field development plan, reflecting an extremely efficient waterflood. 4D seismic spectacularly images extensive sweep away from injectors and excellent reservoir connectivity. Throughout the development, the application of seismic technologies has been a key enabler for effective reservoir management and, looking forward, maximizing value.
The Starling, Scoter and Merganser fields, Blocks 22/30a and 29/3a, UK North Sea
Authors: Freeman C. J. F. , Garrard R. J. , Farwana A. 
Published: October 2020

Abstract
The Shearwater Field is located 242 km east of Aberdeen in the Central North Sea (CNS) and has three satellite fields, Starling, Scoter and Merganser. Acting as the hub for the gas-condensate-producing normal-pressure–normal-temperature (NPNT) satellites, Shearwater, which produces high-pressure–high-temperature (HPHT) Jurassic reservoirs, comprises a bridge-linked wellhead jacket to a production platform. The satellites, developed as subsea tiebacks, target Paleocene turbidite reservoirs, with the Starling Field most distant at 33 km from the host while Merganser is tied in via Scoter through a 15 km pipeline. Each satellite consists of a subsea manifold connected to two production wells at Merganser, and three production wells each at Scoter and Starling. All reservoir traps at the satellites are due to Permian-age Zechstein salt diapirs. Starling and Scoter produce Forties Sandstone Member reservoirs via three deviated wells targeting anticline structures. At Merganser, two long horizontal production wells cross over 4000 ft of faulted Paleocene reservoir intervals to produce under salt diapir overhangs. The satellites have been instrumental in maintaining the Shearwater facilities given early main field well failures, whilst recent challenges have developed as the satellites mature, requiring infill wells and well interventions to maximize economic recovery.
The Kraken and Kraken North fields, Block 9/2b, UK North Sea
Authors: Parkes L. , Wood P. , Macdonald C. 
Published: October 2020

Abstract
The Kraken and Kraken North fields lie in the UK Continental Shelf Block 9/2b on the East Shetland Platform. Hydrocarbons are stratigraphically trapped within Heimdal Sandstone Member of the Lista Formation. The fields lie at around 3900 ft true vertical; depth subsea and the oil is heavy (13–15°API) and viscous.
The field is developed via a waterflood scheme with long horizontal production and injection wells, alternating across the field. To date, 21 development wells have been drilled, with further wells planned. Reservoir quality is extremely good with porosity around 36% and permeabilities in the range of 2–10 D. The field is produced via the Armada Kraken floating production storage and offloading vessel. Developed stock tank oil originally in place is in the region of 400 MMbbl, with further currently undeveloped resources to the west of the field.
The Wingate Field, Blocks 44/23b, 44/24b and 44/19f, UK North Sea
Authors: Huis in't Veld Richard , Schrijver Bart , Salzwedel Alexander 
Published: October 2020

Abstract
The Wingate gas field was discovered in August 2008 by Wintershall's exploration well 44/24b-7, which targeted a Base Permian closure with subcropping reservoirs of the Late Carboniferous Lower Ketch Formation. Pre-drill, significant upside was identified as a result of ConocoPhillips’ nearby 44/23b-13 well (2006), where the Westoe Coal Formation provides a seat seal to the Lower Ketch Formation. Because of the significant difference in free water level between the two wells, the volumetric uncertainty of undrilled compartments with reservoirs in the Lower Ketch, as well as the Caister Coal Formation, remained relatively high. To manage development risk and uncertainty without further appraisal expenditure, and to allow for early gas production, a phased field development was planned: that is, to appraise through development and production. Gas production, through a six-slot platform and export to the Dutch D15-A platform, commenced in October 2011, only 3 years after discovery. Initial development comprised the tieback of the exploration well and drilling of the second compartment with well 44/24b-A2Y. Subsequently, three more compartments were drilled as soon as production dropped off plateau. During the appraisal/development and 7 years of production, knowledge of the reservoirs increased significantly, improving the understanding of the challenging Westphalian gas play.
The Clair Field, Blocks 206/7a, 206/8, 206/9a, 206/12a and 206/13a, UK Atlantic Margin
Authors: Robertson A. G. , Ball M. , Costaschuk J. , Davidson J. , Guliyev N. , Kennedy B. , Leighton C. , Nash T. , Nicholson H. 
Published: October 2020

Abstract
The Clair Field is a giant oilfield containing in the region of 6–7 Bbbl of stock tank oil initially in place, located approximately 75 km west of the Shetland Islands. As such, it represents the single biggest hydrocarbon accumulation on the UK Continental Shelf. Clair was discovered in 1977, but first production did not occur from Phase 1 until 2005, after a lengthy appraisal period. The major appraisal milestone occurred in 1991 after well 206/8-8 proved up fractured clastic red beds of the Devonian Lower Clair Group. This was followed up with an extended well test on 206/8-10Z, which demonstrated the longer-term performance of the reservoir. Further appraisal on Clair Ridge led to the sanction of the Clair Ridge, which came on stream in November 2018. Following the Greater Clair appraisal programme in 2013–15, development options are currently being worked for Clair South, which will develop the Lower Clair Group reservoirs together with overlying shallow-marine reservoirs of the Cretaceous and Jurassic.
The Brechin Field, Block 22/23a, UK North Sea
Authors: Goffey G. , Lunn S. , Seedhouse J. 
Published: October 2020

Abstract
The Brechin Field was discovered by Paladin Resources in 2004. The reservoir is the Paleocene Forties Sandstone Member, with oil trapped in a small dip closure. The prospect was identified as a bright anomaly on a fluid volume processed as part of a 4D survey. However, the anomaly was not consistent with rock physics modelling, and an earlier processed version of the baseline 3D survey showed the opposite response to the 4D datasets. It was established that the fluid anomaly on the 4D data resulted from constructive interference between reflections from the oil–water contact and from top reservoir. Thus, both versions of the data were responding to the presence of hydrocarbons.
The discovery well, 22/23a-7, encountered 137 ft of gross oil-bearing reservoir. Without testing or further appraisal, the field was developed in 2005 with a single production well tieback to the Arbroath platform, via the production manifold at Arkwright Field. Brechin is now operated by Repsol Sinopec Resources and cumulative production to mid-2018 was 4.4 MMbbl. Seismic attributes and well-developed reservoir understanding from neighbouring analogue fields permitted the necessary de-risking of hydrocarbon presence, recovery and volumetric uncertainty, to permit the development of an otherwise economically marginal resource.
The Grove Field, Blocks 49/10a, 49/9c, 49/10c, UK North Sea
Authors: van Oorschot Rene , Smit Willeke , Glebova Anzhela 
Published: October 2020

Abstract
The Grove gas field is located in the Southern North Sea, within the UK offshore licence Blocks 49/10a, 49/9c and 49/10c. The field lies 180 km east of the Humberside coast and 4 km from the UK–Netherlands median line on the western margin of the Cleaver Bank High. The reservoir consists of late Westphalian C fluvial red beds interbedded with mud-prone floodplain deposits. Grove was put on production in 2007 through a single normally unmanned platform which is connected to the Markham J6A facilities by means of a 13.4 km 10-inch pipeline and subsequently exported to Den Helder in the Netherlands. The field has been developed by means of six production wells, targeting a variety of fault blocks and sandstone units. Reservoir complexity due to differential erosion, heterogeneity and faulting has presented development challenges and productivity per well is highly variable. Additionally, the evaporites within the overlying Zechstein Group present drilling and well integrity issues.
The Mungo Field, Blocks 22/20a and 23/16a, UK North Sea
Authors: Baniak G. M. , Sayer Z. , Patterson H. , Gooder R. , Laing N. , Love A. 
Published: October 2020

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.
The Rhyl Field, Block 113/27b, UK East Irish Sea
Authors: Patroni Zavala J. A. , Taylor M. , Tiltman C. J. , Sime N. G. 
Published: October 2020

Abstract

The Rhyl Field is located in the offshore East Irish Sea Basin, approximately 30 km to the west of Barrow-in-Furness. Rhyl is one of the producing gas fields forming the Morecambe Hub development, operated by Spirit Energy. The Rhyl reservoir is the Ormskirk Sandstone Formation of Triassic age which regionally comprises four depositional facies types: aeolian, fluvial, sandflat and playa. The depositional system provides excellent reservoir properties that are impacted by a diagenetic history of authigenic illitization and quartz overgrowths. The northern boundary of the field is located underneath the Fleetwood Dyke Complex, resulting in significant imaging and depth-conversion uncertainty. This has been addressed by dyke mapping and manual depth corrections to seismic processing. The trapping mechanism at the southern boundary of the field is also unclear; the dip-closed structural spill point as mapped at the southern boundary appears shallower than the log-derived gas–water contact. Rhyl gas contains a significant inert content: 37% CO
2
and 7% N
2
. The field's production rate has been limited to approximately 40 MMscfgd by the CO
2
processing limit of the onshore gas terminal. Material balance studies have yielded a satisfactory understanding of connected gas in place, recoverable reserves and dynamic field behaviour.
The Wood, Cayley, Godwin and Shaw fields, Blocks 22/17s, 22/18a and 22/22a, UK North Sea
Authors: Baldwin A. 
Published: October 2020

Abstract
The Upper Jurassic Wood, Godwin, Shaw and Cayley fields lie in Quadrant 22 on the Forties–Montrose High (FMH), a major intra-basinal high bisecting the Central Graben. The Wood Field was the first to be discovered in 1996 by Amoco. The field was later developed by Talisman Energy in 2007 via a single subsea horizontal producer tied back to the Montrose Alpha Platform. The Cayley, Godwin and Shaw discoveries followed during a drilling campaign carried out by Talisman Energy between 2007 and 2009 and were later developed, with the last field coming online in 2017. The fields are all complex structural and stratigraphic traps with reservoir in the Fulmar Formation. The Fulmar Formation on the FMH records an overall transgression, becoming progressively younger updip, with each field exhibiting a different diagenetic and depositional history in response to the unique evolution of the inter-pod in which they reside. The combined oil in place for the fields is currently estimated at 222 MMboe with an expected ultimate recovery of 84 MMboe. The addition of these reserves has been instrumental in helping to extend the life of the Montrose and Arbroath Platforms beyond 2030.
The Sean fields, Block 49/25a, UK North Sea
Authors: Botman R. J. , van Lier J. 
Published: October 2020

Abstract
Block 49/25a contains the Sean gas fields, Sean North, Sean South and Sean East – collectively known as the Greater Sean area and discovered in 1969. The fields are located in the Southern Gas Basin, about 15 km SE of the Indefatigable gas field. Approximately 1.1 tcf of gas is trapped in a series of fault-bounded dip closures consisting of Permian sandstones belonging to the Leman Sandstone Formation (Rotliegend Group). The reservoir is overlain by evaporites of the Late Permian Zechstein Group. The fields are characterized by excellent Leman reservoir quality, and resources have increased significantly over the years. The reservoir largely behaves as a well-connected tank, which has resulted in high recovery factors (>90%).
In 2015, Oranje-Nassau Energie UK Ltd (ONE) took over operatorship of the field through purchasing the rights of both Shell and Esso, giving ONE a 50% operated interest together with SSE E&P UK Ltd (SSE). In 2017, an infill well (SSPD05) was drilled by ONE to test a pop-up structure situated between Sean North and Sean South. The well found, as expected, partially depleted reservoir but has proven to accelerate production and add incremental reserves to the field.
The Lennox Field, Blocks 110/14c and 110/15a, UK East Irish Sea
Authors: Bunce J. 
Published: October 2020

Abstract

The Lennox Field is a saturated oilfield with a significant primary gas cap at initial conditions. Located in the East Irish Sea withincBlocks 110/14c and 110/15a, the field was discovered in 1992. First oil was achieved in February 1996. Lennox is a rollover anticline structure. The Triassic Ormskirk Sandstone Formation reservoir comprises good-quality aeolian and fluvial sandstones with typicalcporosities of 11–21%. The gas column reaches a height of
c.
850 ft and overlays a 143 ft oil column. Oil initially-in-place is estimated to be 202 MMbbl, whilst total gas initially-in-place is 521 bcf. The field has been developed by a wellhead platform tied-back to the neighbouring Douglas Complex. The field development has been split into two phases: the first phase focused on oil production and involved the drilling of 12 horizontal and multilateral production wells and two gas injection wells. Oil production ceased in 2012 with total produced volumes of 103 MMbbl. The second phase comprised the gas cap blowdown, and the optimization of the existing well stock for gas production. Eni UK acquired the operatorship of the field in April 2014 and has focused on maximizing and accelerating gas production from the field.
The UK North Sea: a history of oil and gas
Authors: King Lucy 
Published: October 2020

Abstract
With a history spanning over 50 years, the UK Continental Shelf (UKCS) is one of the most explored and mature basins in the world. Over 44 Bbbl of reserves have been recovered from over 450 fields across the UKCS, enabled by continuous improvement in seismic, drilling and development technologies. Starting in 1965 with BP's West Sole discovery in the Southern Gas Basin, every sector of the UKCS has since opened up. But it is not just the discoveries that have characterized this ultra-mature region. It has weathered a turbulent history of oil prices, fiscal changes, an ever-changing corporate environment and the industry's worst offshore disaster, which serves as a reminder of the uncompromising conditions of the North Sea.
Production peaked at the turn of the millennium, and it is only since 2013 that there has been a partial reversal of the declining trend. With discoveries getting scarcer and smaller, maintaining the trend will not be easy, especially with the number of companies exiting the region for more prospective global opportunities on the rise. However, with an estimated 10–20 Bbbl yet to find in the basin, there is still a lot to play for in the coming years.
The Shearwater Field, Blocks 22/30b and 22/30e, UK North Sea
Authors: Taylor B. J. , Jones D. W. 
Published: October 2020

Abstract
The Shearwater Field is a high-pressure–high-temperature (HPHT) gas condensate field located 180 km east of Aberdeen in UKCS Blocks 22/30b and 22/30e within the East Central Graben. Shell UK Limited operates the field on behalf of co-venturers Esso Exploration and Production UK Limited and Arco British Limited, via a fixed steel jacket production platform and bridge-linked wellhead jacket in a water depth of 295 ft.
Sandstones of the Upper Jurassic Fulmar Formation constitute the primary reservoir upon which the initial field development was sanctioned; however, additional production has been achieved from intra-Heather Formation sandstones, as well as from the Middle Jurassic Pentland Formation. Following first gas in 2000, a series of well failures occurred such that by 2008 production from the main field Fulmar reservoir had ceased. This resulted in a shut-in period for the main field from 2010 before a platform well slot recovery and redevelopment drilling campaign reinstated production from the Fulmar reservoir in 2015. In addition to replacement wells, the redevelopment drilling also included the design and execution of additional wells targeting undeveloped reservoirs and near-field exploration targets, based on the lessons learned during the initial development campaign, resulting in concurrent production from all discovered reservoirs via six active production wells by 2018.
The Lomond Field, Block 23/21, UK North Sea
Authors: Jena Srmuti , Olowoleru David 
Published: October 2020

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.