Abstract 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.

Abstract The Buzzard Field remains the largest UK Continental Shelf oil discovery in the last 25 years. The field is located in the Outer Moray Firth of the North Sea and comprises stacked Upper Jurassic turbidite reservoirs of Late Kimmeridgian–Mid Volgian age, encased within Kimmeridge Clay Formation mudstones. The stratigraphic trap is produced by pinchout of the reservoir layers to the north, west and south. Production commenced in January 2007 and the field has subsequently produced 52% over the estimated reserves at commencement of development, surpassing initial performance expectations. Phase I drilling was completed in 2014 with 38 wells drilled from 36 platform slots. Platform drilling recommenced in 2018, followed in 2019 by Phase II drilling from a new northern manifold location. The evolution of the depositional model has been a key aspect of field development. Integration of production surveillance and dynamic data identified shortcomings in the appraisal depositional model. A sedimentological study based on core reinterpretation created an updated depositional model, which was then integrated with seismic and production data. The new depositional model is better able to explain non-uniform water sweep in the field resulting from a more complex sandbody architecture of stacked channels prograding over underlying lobes.

Abstract The Captain Field in Block 13/22a is in the Moray Firth region of the UK North Sea. The primary reservoirs are Lower Cretaceous turbidite sandstones of the Captain Sandstone Member. Upper Jurassic shallower-marine Heather Formation sandstones of Oxfordian age provide a secondary reservoir. Total oil in place exceeds 1 Bbbl; however, the oil is heavy and viscous, requiring the continuous application of innovative technologies to maximize economic recovery from the field. Captain has been producing since 1997, with reservoir waterflood planned from the outset. Captain has been developed using long horizontal producers to maximize reservoir contact. Water injectors provide pressure support, with the aim of full voidage replacement. The Captain development has been phased with facilities consisting of two bridge-linked platforms, a floating production, storage and offloading vessel, and two subsea manifolds. Peak oil rate (100 000 boepd) was achieved in 2002. Average production in 2019 was 28 000 boepd. Captain is executing a chemical enhanced oil recovery (EOR) project, a first for the UK North Sea. Conventional waterflood yields an estimated ultimate recovery of 30–40%. Chemical EOR is expected to improve this by 5–20% in areas of the reservoir under polymer flood.

Abstract The Golden Eagle Field is located 18 km north of the Buzzard Field in the Moray Firth, and consists of oil accumulations in the Lower Cretaceous Punt and Upper Jurassic Burns Sandstone members. The development area comprises three fields, Golden Eagle, Peregrine and Solitaire, but up to 90% of the oil-in-place and ultimate recovery are in Golden Eagle. The two satellite fields are primarily structural closures, while the Golden Eagle Field reservoirs have a major element of stratigraphic pinchout. Production commenced in October 2014 and approximately 140 MMbbl of recoverable oil is anticipated over its field life from the 19 development wells (14 producers and 5 injectors) that form the initial development phase. Production performance to date has exceeded expectations, aided through the use of completions that provide zonal control of the reservoir units which has successfully supported reservoir management and improved sweep efficiency. A number of significant lessons have been learned during the early stages of the field life from the integration of dynamic data (real-time downhole fibre-optic reservoir monitoring instruments, inter- and intra-well tracers, and well interference tests) and seismic data improvements (post-start-up acquisition of high-density ocean-bottom node seismic and depth-conversion improvements).

Abstract The Goldeneye gas-condensate field lies in the Moray Firth Basin in the UK Continental Shelf (UKCS) approximately 100 km off the NE coast of Scotland. The field was discovered in 1996 as a normally pressured accumulation with estimated gas-initially-in-place (GIIP) of 810 bcf with a thin oil rim in the Lower Cretaceous Captain Sandstone Member in a three-way, dip-closed structure. Field development included five production wells, with first gas achieved in 2004. Goldeneye was steadily produced under moderate aquifer support until cessation of production (COP) in 2010 following water breakthrough at the wells. Over its lifetime Goldeneye has produced 568 bcf of gas and 23 MMbbl of condensate. Around the time of COP, the UK Carbon Capture and Storage Commercialisation Competition was announced, and Goldeneye was evaluated as a candidate. The removal of significant volumes of hydrocarbons through production left remaining capacity that could be refilled without reservoir pressure significantly exceeding virgin conditions. However, following withdrawal of funding from the UK Government in 2015, the project was put on hold. Since then additional subsurface work has been conducted to support the successful abandonment of the development wells, which had previously been suspended since 2010.

Abstract The Perth Field was discovered in 1983 and appraised from 1992 to 1997, but has remained undeveloped due to the lack of a suitable export solution for the sour fluids. The field is a combined structural–stratigraphic trap on the southern edge of the Tartan Ridge in the Outer Moray Firth. An oil column of >1000 ft is developed in the turbiditic Upper Jurassic Claymore Sandstone Member which is mostly 500–800 ft thick in the proven appraised Core Perth area. Reference case oil in place within Core Perth is estimated at 197 MMbbl. An undrilled northern terrace may contain a similar amount of oil, with an additional 40 MMbbl estimated to be in place in a separate, proven northeastern fault panel. Potential development by subsea tieback to the Scott platform became an option in 2017. P50 reserves for 15 years’ production from Core Perth (five producers and two water injectors) are estimated at 47.3 MMbbl (24% recovery factor). The preferred concept is for oil and gas to be processed on a new self-contained sour module located on a standalone structure at Scott with oil exported in the Forties Pipeline System. Sour gas would be incinerated in a dedicated flare with recovered hydrocarbon gas exported to Scott.

Abstract The Rubie Field is located within the Outer Moray Firth in Block 15/28b, towards the eastern end of the Renee Ridge and 6 km east of the Renee Field. The block was awarded to a BNOC-operated group following the 7th Licensing Round in 1980. The 15/28b-4 discovery was drilled by Britoil in 1985, encountering hydrocarbons at two stratigraphic levels within the Paleocene Andrew Sandstone unit and Eocene Cromarty Sandstone Member reservoirs. No further appraisal was undertaken prior to a late 1997 Annex B submission for a joint Renee and Rubie Field development by new operator, Phillips Petroleum. The Rubie development plan comprised a single 6000 ft Andrew Sandstone horizontal producer which was completed in March 1999 and tested at an initial rate of 9700 bopd and 1.65 MMscfgd. Export of fluids was via a 6 km-long pipeline to the Renee Field manifold and then onwards to the host facility in the Ivanhoe–Rob Roy fields. Rubie was brought on stream on 29 May 1999. Abandonment was originally scheduled for end 2006, but field-life extension initiatives deferred cessation of production (COP) to March 2009. Cumulative Andrew Sandstone production at COP was 11.5 MMbbl and the oil recovery factor 50%, based on a final mapped oil-in-place of 23 MMbbl.

Abstract The UK Oil & Gas Authority carried out post-well failure analyses of exploration and appraisal wells in the Moray Firth and the UK Central North Sea to fully understand the basis for drilling the prospects and the reasons why the prospects failed. The data consisted of Tertiary, Mesozoic and Palaeozoic targets/segments associated with 97 wells drilled from 2003 to 2013. Seal was the primary reason for failure followed by trap, reservoir and charge. Root causes for failure were a lack of lateral seal, the absence of the target reservoir and the lack of a trap. The main pre-drill risk was not accurately predicted in over one-third of the cases and a third of the segments were targeted on the basis of perceived Direct Hydrocarbon Indicators. This study identified a number of interpretation gaps and pitfalls that ultimately contributed to the well failures. These included poor integration, improper application of geophysics, lack of regional play context, and absent or ineffective peer review. Addressing these gaps in a comprehensive and systematic way is fundamental to improving exploration success rates.

Abstract The Goldeneye gas–condensate field lies in the Moray Firth Basin of the North Sea and illustrates the potential for further field life after the normal end of production. It was discovered in 1996 in a three-way dip-closed structure in the Lower Cretaceous Captain Sandstone. Five development wells were drilled from a single production platform and first gas was produced in 2004. The field pressure decline indicated partial aquifer support and no compartmentalization. Approaching the end of production, the opportunity arose to propose Goldeneye as a store for CO 2 . The cap-rock seal was capable of containing gas and the removed hydrocarbons left a significant volume that could be refilled without raising pressures above original conditions. The field's good reservoir properties were favourable for injection, the wellstock and infrastructure were modern, and CO 2 sources were available close by. The different requirements of a storage project called for a detailed understanding of the overburden to guard against possible leak paths and to identify secondary containment. Furthermore, greater understanding of the aquifer was needed as it limits storage volumes through its impact on reservoir pressures. Updated interpretation, analysis and modelling demonstrated that Goldeneye is an excellent potential CO 2 storage site, which gives it a possible second span of life helping to offset UK CO 2 emissions.