bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental investigation and constitutive modeling of the behaviour of highly plastic Lower Rhine clay under monotonic and cyclic loading
Authors: Tafili Merita , Wichtmann Torsten , Triantafyllidis Theodoros
Published: October 2020

A new experimental series on the highly plastic (plasticity index, IP = 34%) Lower Rhine clay (LRC) is presented. The study comprises tests on normally as well as overconsolidated samples under monotonic and cyclic loading. The loading velocity has been varied to evaluate the strain rate dependency of the LRC behaviour, testifying the well-known reduction of undrained shear strength with decreasing displacement rate. Isotropic consolidation followed by a cyclic loading with constant deviatoric stress amplitude leads to a failure due to large strain amplitudes with eight-shaped effective stress paths in the final phase of the tests. The inherent anisotropy has been additionally evaluated using samples cut out in either the vertical or the horizontal direction. Furthermore, the behaviour of LRC is compared with the behaviour of low plastic kaolin silt (IP = 12.2%). A new visco-hypoplastic-type constitutive model with a historiotropic yield surface has been used to simulate some of the experiments with cyclic loading. Even the eight-shaped stress loops at cyclic mobility are reproduced well with this model. The data of this paper can be also used by other researchers for the examination, calibration, improvement, or development of constitutive models dedicated to fine-grained soils under monotonic and cyclic loading.
Digital Bifurcation Analysis of Internet Congestion Control Protocols
Authors: Beneš Nikola , Brim Luboš , Pastva Samuel , Šafránek David
Published: October 2020

Digital bifurcation analysis is a new algorithmic method for exploring how the behavior of a parameter-dependent discrete system varies with a change in its parameters and, in particular, for the identification of bifurcation points where such variation becomes dramatic. We have developed the method in an analogy with the traditional bifurcation theory and have successfully applied it to models taken from systems biology.

In this paper, we report on the application of the digital bifurcation analysis for analyzing the stability of internet congestion control protocols by inspecting their attractor bifurcations. In contrast to the analytical methods, our approach allows fully automated analysis.

We compared the robustness of the basic Random Early Drop (RED) approach with four substantially different extensions, namely gentle, adaptive, gradient descent, and integral feedback RED. The basic RED protocol is well known to exhibit unstable behavior when parameters are varied. In the case of adaptive and gradient descent RED protocol, the analysis showed significant improvements in stability, whereas in the results for gentle and integral feedback RED protocols the improvement was negligible. We performed a series of model simulations, the results of which were in accordance with our bifurcation analysis. Based on our results, we can recommend both adaptive and gradient descent RED to improve the robustness of the RED protocol.
Dynamics of a High-Order Generalized Lorenz Model for Magnetoconvection
Authors: Pati N. C. , Rech Paulo C.
Published: October 2020

In this paper, we present a 6D generalized Lorenz model for magnetoconvection of an electrically conducting viscous fluid layer subjected to horizontally imposed uniform magnetic field. It generalizes the 4D generalized Lorenz model of Macek and Strumik [Phys. Rev. E 82, 027301 (2010)] taking into account high-wavenumber vertical Fourier modes of the temperature profile. These additional modes not only increase the feedback loop of the system but also subsequently affect the transitional processes. The boundedness, stability of solutions, bifurcation patterns enroute to chaos for the new 6D model are explored. Studies reveal that the stability of the quiescent state does not alter. But the stability of the steady convective state differs in comparison to the 4D model. The regions of aperiodic oscillation are suppressed which results in stabilization of the convective motion. Some new organized periodic structures embedded in chaotic domain appear in parameter space of the 6D model, and the transitional route to hyperchaos is altered owing to the inclusion of the high-order modes.
INTERFERENCES EFFECTS BETWEEN OSTEOCYTES LOCATED AT THE SAME ZONE DURING BONE REMODELING PERIOD: A THEORETICAL AND NUMERICAL STUDY
Authors: BOUCETTA ABDELKADER , BOUKHAROUBA TAOUFIK , RAMTANI SALAH , HAMBLI RIDHA
Published: October 2020

Background: Several analytical models have been developed in the past to analyze the specific role of osteocytes in the process of bone remodeling, which can be considered as the response of bone material to functional requirements. Most of them considered both the number of osteocytes and their spatial distribution in one area of influence, while others suggested in addition to include considerations of the size of the basic multi-cellular unit. Methods: Taking advantage of previous works, the standard model equation is revisited by incorporating two complementary parameters: (a) the possibility of resorption of osteocytes, apoptosis or function inhibition during remodeling process triggered by the transduction phase of osteocytes embedded within the bone matrix and; (b) the interference of influence zones for the same osteocyte. Results: Bone density evolution has been calculated starting with a medical imaging of an implanted femur. It is shown that the management of interference zone and the possibility of resorption or inhibition of osteocytes have a direct impact upon the value of the mechanical stimulus and hence on the recruitment of Bone Multicellular Units (BMUs). From a mathematical point of view, this effect has been considered by modifying mechanical stimulus of the standard model such that it is impacted by a scalar factor ranged in the interval (0.5–1). Conclusion: It is clearly demonstrated that predicted of the added bone mass amount shows that the new model is more active in low density regions where requiring rapid adaptation to the behavior of the implant, and that the standard model takes the lead in the regions with high density.
The Innes Field, Block 30/24, UK North Sea
Authors: Gluyas J. G. , Arkley P.
Published: October 2020

The abandoned Innes Field was within Block 30/24 on the western margin of the Central Trough in the UK sector of the North Sea. Hamilton Brothers Oil Company operated the licence, and Innes was the third commercially viable oil discovery in the block after Argyll and Duncan. It was discovered in 1983 with well 30/24-24. Three appraisal wells were drilled, one of which was successful. Oil occurs in the Early Permian Rotliegend Group sandstones sealed by Zechstein Group dolomites and Upper Jurassic shale.

The discovery well and successful appraisal well were used for production. Export of light, gas-rich crude was via a 15 km pipeline to Argyll. Innes was produced using pressure decline. It was abandoned in 1992 having produced 5.8 MMbbl of oil and possibly 9.8 bcf of gas. Water cut was a few percent.

Innes was re-examined between 2001 and 2003 by the Tuscan Energy/Acorn Oil and Gas partnership with a view to tying the field back to the newly redeveloped Argyll (Ardmore) Field but marginal economics and financial constraints for the two start-up companies prevented any further activity. Enquest currently owns the licence and the company has redeveloped Argyll/Ardmore, as Alma. There are no plans to redevelop Innes.
The Pilot, Elke, Blakeney, Narwhal, Harbour and Feugh fields, Blocks 21/27, 21/28, 28/2 and 28/3, UK North Sea
Authors: Brown Stephen A. , Wood Peter H. , Bamford Maurice L. F. , Gluyas Jon G.
Published: October 2020

The, as yet undeveloped, heavy-oil fields of the Western Platform contain about 500 MMbbl of oil in place. The fields are reservoired in highly porous and permeable, Middle Eocene, deep-water sandstones of the Tay Sandstone Member, deposited as turbidite flows from a shelf immediately to the west.

Oil gravity varies from 19° API in the Harbour Field to 12° API in the northern end of the Pilot Field. The reservoirs are shallow: Pilot and Harbour are at about 2700 ft TVDSS, with the Narwhal, Elke, Blakeney and Feugh discoveries being deeper at about 3300 ft TVDSS. Overall, oil viscosity decreases and API oil gravity increases with depth.

To date, the high oil viscosity has precluded development of these discoveries, and many previous operators have considered various development schemes, all based on water flood.

The development of the Pilot Field is being planned using either a hot-water-flood, steam-flood or polymer-flood approach, which all have the potential of achieving a very high recovery factor of 35–55%. Steam has been evaluated in most detail and about 240 MMbbl could be recovered should all of these discoveries be steam flooded.
The Renee Field, Block 15/27a, UK North Sea
Authors: Tegerdine Graham
Published: October 2020

The Renee Field lies in Block 15/27 toward the eastern end of the Renee Ridge, a major intra-basinal high in the Outer Moray Firth separating the Witch Ground Graben and South Halibut Graben. The block was awarded to a Phillips Petroleum-led consortium in the fourth Round of UKCS Licensing in March 1972. The 15/27-1 discovery well was drilled in 1976, testing oil at rates of 8025 bopd from stacked Piper/Upper Scott sandstone reservoirs. The field was appraised in mid-1997 and an Annex B submitted to the Department of Trade and Industry in late 1997 for a joint Renee and Rubie Field development. Oil export was via a 21 km pipeline to the Ivanhoe/Rob Roy fields, north of Renee. The development comprised a three-well drilling programme, completed in August 1999. First production was achieved in February 1999 at rates of up to 20 000 bopd, the plateau period continuing until year end. Production continued to decline until the field was permanently shut-in during September 2006. Ultimate recovery was 8.9 MMbbl and recovery factor 49%, based on a final mapped stock tank oil-in-place of 18.2 MMbbl. Decommissioning of the Renee Field commenced in 2015 with the removal of the subsea infrastructure.
The Elswick Field, Bowland Basin, UK Onshore
Authors: Hampson Mathew , Martin Heather , Craddock Lucy , Wood Thomas , Rylands Ellie
Published: October 2020

The Elswick Field is located within Exploration Licence EXL 269a (Cuadrilla Resources Ltd is the operator) on the Fylde peninsula, West Lancashire, UK. It is the first producing onshore gas field to be developed by hydraulic fracture stimulation in the region. Production from the single well field started in 1996 and has produced over 0.5 bcf for onsite electricity generation. Geologically, the field lies within a Tertiary domal structure within the Elswick Graben, Bowland Basin. The reservoir is the Permian Collyhurst Sandstone Formation: tight, low-porosity fluvial desert sandstones, alluvial fan conglomerates and argillaceous sandstones. The reservoir quality is primarily controlled by depositional processes further reduced by diagenesis. Depth to the reservoir is 3331 ft TVDSS with the gas–water contact at 3400 ft TVDSS and with a net pay thickness of 38 ft.
The Vale of Pickering gas fields: Kirby Misperton, Malton, Marishes and Pickering, North Yorkshire, UK Onshore
Authors: Harrison D. , Haarhoff M. , Heath-Clarke M. , Hodgson W. , Hughes F. , Ware D. , Mortimer A.
Published: October 2020

The Vale of Pickering gas fields were discovered over a 20-year period. The development scheme was aimed to deliver 9.3 MMscfd gas to the Knapton Power Station nearby. Cumulative production is 30.3 bcf from an estimated 172 bcf gas initially in place. The gas fields comprise a series of low relief structures at depths around 5000 ft true depth subsea. The primary reservoir is Zechstein Group dolomitized and fractured carbonates of the Permian Kirkham Abbey Formation with average reservoir quality ranges of 12–13% porosity and 0.5–1.5 mD permeability. Secondary reservoirs exist in Carboniferous sandstones directly below the Base Permian Unconformity. The gas is sourced from Lower Carboniferous shales. The fields were discovered using 2D seismic data and subsequent 3D seismic data have been merged to form a 260 km
2
dataset. Zechstein production has been limited by early water breakthrough. Artificial lift is planned to enhance the gas flow rate on the Pickering Field and anticipated water influx will be re-injected. If this enhanced gas recovery scheme is successful it can be applied to the other fields. Plans to hydraulically fracture a number of zones in the Carboniferous Lower Bowland Section are in progress.
The Forties Field, Blocks 21/10 and 22/6a, UK North Sea
Authors: Rose P. T. S. , Byerley G. W. , College E. , Pyle J. R. , Ralph D. J. , Rowbotham P. S. , van Oorschot L. A. , Towart J. , Vaughan O. , Vermaas M.
Published: October 2020

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.
The Blake Field, Blocks 13/24a and 13/29b, UK North Sea
Authors: Saundry E. , Colmenares J.
Published: October 2020

The Blake Field is subdivided into two discrete parts, the ‘Channel’ and the ‘Flank’ areas. The two areas are geologically different but also reflect the different levels of maturity in terms of their development. Blake Channel was discovered in 1998, with first production commencing in 2001. Blake Flank was discovered in 1974 and developed in 2003.

The field contains saturated light oil, with a field-wide oil–water contact and two significant gas caps. The reservoir comprises deep-water turbidite sands of Lower Cretaceous age.

The combination of complex depositional environment and dynamic data resulted in the decision in 2016, to create a new model incorporating a fully integrated approach to subsurface evaluation and modelling. The latest work summarized in this paper incorporates a new geological interpretation along with the addition of aquifer extensions to capture depletion from offset fields, and a palaeo-oil leg, to help limit aquifer influx and improve history match. 4D seismic has also been incorporated to support the evaluation. Blake Channel and Flank have oil-in-place of 230 MMbbl and 300 MMbbl and have produced 94 MMbl and 15 MMbbl, respectively, to date.
The Buchan Field, Blocks 20/5a and 21/1a, UK North Sea
Authors: Wynn T. , Saundry E.
Published: October 2020

The Buchan Oilfield is a large mature field, now suspended, located in the Moray Firth. The field is situated 153 km NE of Aberdeen in water depths of
c.
122 m. The reservoir comprises an overpressured and fractured Upper Devonian–Early Carboniferous fluvio-lacustrine sandstone. Production was via high permeability channel sandstones and permeable faults and fractures. The Buchan Field was brought onto production in May 1981 by BP Petroleum Development Ltd via the Buchan Alpha semi-submersible floating production vessel (FPV). The oil column is
c.
2000 ft in height with a matrix stock tank oil initially in place (STOIIP) range of 322–471–668 MMbbl. Production from the ten vertical development wells was driven by pressure depletion (over 5000 psi since first oil) coupled with weak aquifer influx. Production from the Buchan Field ceased on 13 May 2017 after having produced 147.8 MMbbl. The Buchan FPV was subsequently taken off-station during August 2017. A new facility or tie-back redevelopment option will be required to access the remaining resources which are in the range of 20–90 MMbbl depending on the STOIIP, the production mechanism and the potential development plan.
The Burghley Field, Block 16/22, UK North Sea
Authors: Heath R. , Robertson K.
Published: October 2020

The Burghley Field is a Paleocene oil field located in Block 16/22 on the UK Continental Shelf about 8.5 km NE of the Balmoral Field, in a water depth of
c.
143 m. Burghley produces undersaturated oil from sandstones of the Maureen Formation. It comprises a low relief four-way dip-closed structure located on the SE end of the Fladen Ground Spur. The field was discovered in 2005 by well 16/22-7. Overall nine well penetrations were drilled prior to the commitment to develop the field. The Burghley Field was brought on-stream in October 2010 as a single subsea horizontal well development tied back to the Balmoral floating production vessel. The current estimate for oil in place is
c.
20 MMbbl for the entire field, with approximately 12 MMbbl in the core area where the development well is located. The expected ultimate recovery is approximately 5.65 MMbbl.
The Enoch Field, Block 16/13a, UK North Sea
Authors: Robertson K. , Heath R. , McKenzie A.
Published: October 2020

The Enoch Field is located in the South Viking Graben and straddles the UK/Norway median line with 80% of the field in the UK and 20% in Norway. Enoch produces undersaturated oil from the Early Eocene-age Flugga Sandstone Member of the Sele Formation. Hydrocarbons have been trapped by a combination of compaction-related dip closure and sand pinchout. The current stock tank oil initially in place estimate is
c.
42 MMbbl with expected ultimate recovery of 11.5 MMbbl. The field was brought onstream in May 2007 via a single horizontal subsea gas-lifted well tied back to the Brae Alpha platform. Initial oil production rates were
c.
11 800 bopd. The field is currently in decline and in December 2018 production was
c.
1800 bopd with 80% water-cut. Cumulative oil production to the end of 2018 was 10.581 MMbbl.
The Blane Field, Block 30/3a, UK North Sea
Authors: Robertson K. , Heath R. , Macdonald R.
Published: October 2020

The Blane Field is located in the central North Sea in Block 30/3a (Licence P.111), approximately 130 km SE of the Forties Field, in a water depth of 75 m (246 ft). It straddles the UK/Norway median line with 82% of the field in the UK and 18% in Norway. Blane produces undersaturated oil from the Upper Forties Sandstone Member of the Sele Formation and contains good quality light oil within a four-way structural closure; it has a hydrodynamically tilted original oil–water contact. The field stock-tank oil initially in place estimate is 93 MMbbl with an expected ultimate recovery of 33 MMbbl. Blane first oil was achieved in September 2007. The field has been developed by two horizontal producers located on the central crest of the field supported by a water injector drilled on the NW flank. Oil production peaked at
c.
17 000 bopd in 2007 and the field is currently in decline. By the end of 2018 production was
c.
3000 bopd with 55% water-cut. Cumulative oil production to the end of 2018 was 26.6 MMbbl.
The Corringham, Gainsborough–Beckingham, Glentworth, Nettleham, Stainton and Welton fields, UK Onshore
Authors: Ward Kelsey L. , Folorunso Frank O.
Published: October 2020

This paper focuses on the southern part of the East Midlands oil province, in which most hydrocarbon reservoirs are in Carboniferous strata and are primarily oil producing. The oils are predominantly sourced from the Namurian interbedded shales in the Gainsborough Trough and are trapped within anticlinal structures.

Oil and gas exploration and production in the UK was marked by the Hardstoft-1 discovery in 1919. Since this discovery, more than 33 fields have been discovered in the East Midlands oil province, including the fields studied in this paper: Egmanton (in 1955), Bothamsall and Corringham (in 1958), Gainsborough and Beckingham (in 1959), South Leverton (in 1960), Glentworth (in 1961), and, the UK's second largest onshore field, Welton (in 1981). All of these fields produce from a Carboniferous petroleum system, sourced from Pendleian-age shales, reservoired in Namurian- and Westphalian-age sands, and trapped predominantly via structural, anticlinal traps.
The Pierce Field, Blocks 23/22a and 23/27, UK North Sea
Authors: Hale M. , Laird R. , Gavnholt J. , van Bergen P. F.
Published: October 2020

The Pierce Field lies 250 km east of Aberdeen, in the UK sector of the East Central Graben. The field comprises twin salt diapirs, forming the trap for oil and free gas in the Paleocene–Eocene Forties Sandstone Member reservoir. The diapirs exerted a strong influence over the sedimentation of the reservoir, with the construction of multistorey sandstone bodies forming a complex reservoir geometry further complicated by a hydrodynamic aquifer.

The field currently produces to the Haewene Brim floating production storage and offloading (FPSO) installation, and has undergone several phases of development as the understanding has matured. It was initially developed with six subsea horizontal oil producers tied back to the FPSO, with produced gas reinjected through two gas injectors. In 2004–05, water injection was introduced to South Pierce to provide increased pressure support and improve sweep. To maximize recovery, four additional oil producers were drilled between 2010 and 2016, with the final (third) gas injector drilled in 2010. Production is primarily constrained by topsides gas compression capacity leading to gas/oil ratio optimization being the focus of the current field management strategy.

The final phase of field development, included in the original field development plan, involves depressurization of the field with the installation of a gas export line.
The Huntington Field, Block 22/14a, UK North Sea
Authors: Couch Andrew G. , Eatwell Samantha , Daini Olu
Published: October 2020

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.
The Pelican Field, Block 211/26a, UK North Sea
Authors: Frenz Thurza , Besly Bernard , Marriott Jill
Published: October 2020

The Pelican Field lies in the East Shetland Basin, in Block 211/26, roughly 150 km NE of the Shetland Islands. It was discovered in 1975 by exploration well 211/26-4. Development was delayed until 1995 when economic development became feasible as a subsea tie back to the Cormorant Alpha Platform. The reservoir is the Middle Jurassic Brent Group, comprising sands deposited in a fluvio-deltaic, shallow-marine, wave-dominated system. The reservoir interval has an average thickness of around 300 ft, ranging from 220 ft on the crest to 400 ft in down-flank areas. The crest of the field lies at around 10 500 ft true vertical depth subsea. Current estimate of oil in place for the field is
c.
500 MMbbl. The Pelican Field suffers from significant deterioration of reservoir properties with depth, leading to low recovery factors of 15–20%. To date, 21 production and injection wells have been drilled recovering a total of 76 MMbbl. Oil production started in 1996 and peak oil production was achieved at 50 000 bopd in the same year. Rates declined due to water-cut development in most of the wells and current production rates are around 2000 bopd.