Gyda is a 200MMstb field, located in the North Sea Central Trough, offshore Norway. The field was discovered in 1980, and first oil was produced in 1990. It is one of the deepest, hottest and poorest quality oilfields in the North Sea. The structurally complex field contains three different fluid types, and the crude is asphaltene rich. The shallow marine sandstone reservoir is gently dipping, wedge-shaped, with an oil column of 500m. The field receives no aquifer support and is being developed by waterflood. The connate water/injection water mix has a severe scaling tendency.Development of the field is set against a background of tight cost control within the industry generally, and within the Operating company in particular. With six wells drilled per year, a current offtake rate of 70Mstbpd, and areas of the field showing early mature performance, the challenge is to maintain production whilst keeping costs low. The development is therefore managed by maintaining maximum flexibility in drilling locations, sequence and well use, by use of appropriate technology, and by the innovative use of conventional techniques to exploit the field's characteristics. This paper describes: 1. reservoir complexity; 2. the technologies employed to meet the reservoir management challenges; 3. development philosophy; 4. field management history; and 5. value generation.

Greater Plutonio is BP's largest subsea development with an initial plan to drill and complete 43 high tech, high cost, high rate subsea development wells. A relatively low level of classical field appraisal was possible because of high industry costs coupled with the fast pace of the project. Innovative subsurface management has therefore been required to reduce substantial uncertainty during the development phase. Full use has been made of excellent HiRes seismic data. An optimised well order has been crucial to reduce depth uncertainties and facilitate a focused, early data acquisition programme - while incrementally tackling more and more complex drilling and completion challenges. Extensive learnings have been possible from reservoir interference data resulting from rig-based production and injection tests. The application of some specific technologies has been key to the success of the project: widespread use of a Subsea Acoustic Monitoring System to interrogate downhole pressure data from multiple offset wells prior to subsea system installation; 100% reliance on Subsea MultiPhase Flowmeters during initial ramp-up and subsequent operations; Extensive use of remote sensing technologies relayed real time to office desktops and fully integrated with well models to facilitate immediate well and reservoir management. This has enabled significant reservoir learning and therefore reservoir management not only in the early ramp-up phase but actually before field start-up, which was achieved on 1st October 2007. In turn this has allowed the on-going development drilling order to be honed to maximise early production and injection. The successful subsurface and wells management of Greater Plutonio has been demonstrated by the delivery of sufficient production potential to allow field rates of 200mbd in January 2008 (after just over 3 months of operations) and over 300mmscf/d of injection potential at the time of first gas injection less than 2 months after first oil. In addition, by early 2008 water injection had reached 120mbwd into 4 wells, with potential for a further 40mbwd already completed and tested. Establishment of full voidage replacement in 2008 to allow sustainable plateau production is ahead of plan. The enhanced reservoir understanding from the pre-first oil and ramp-up data has reduced subsurface uncertainties while the Greater Plutonio development has progressed and will play a crucial part in increasing ultimate field recovery.

Copy right 7996 , Stee ri ng Comm ittee of the Euro pean I OR -Symposium . Th is paper was presented at the 8th . Eu ropean I OR -Symposium i n Vienna, Austr i a , May 16 -17 . 1995 Th is paper was setected for presentation by the Stee ring Comm ittee , fol low i ng review of information contai ned in en abstract subm itted by the author(s). The paper, as p resented hes not been reviewed by the Stee ring Committ ee . Abstrac tThe Ula reservoir consists of ons main reservoir unit whic h presently is very we ll swe pt b y injected water, and ons uppe r reservoir uni t from whic h [here i s significantly lower oi l recovery d us to its lower permeability.The paper presents results from a feasibility study which indicates that botte horizontal Wells and WAG injection would increase oil recovery in the upper, low permeable reservoir unit .The WAG potential in the upper unit is highly dependent on a number of parameters, such as the presence of high permeable streaks in the main reservoir unit, the k"/kh ratio in the upper unit and gas relative permeability . The study indicates, however, that although WAG potential from the upper reservoir unit is affected by these parameters, the overall WAG potential remains relatively unchanged . As will be discussed below, changes in critical parameters which significantly reduce the upper unit WAG recovery appears to enhance the main unit recovery .Since the drieling of horizontal Wells located close to the top of the structure affects mainly recovery Erom the upper unit, the potential for this method is more sensitive to changes in upper unit reservoir properties, particularly the k,lkh ratio, but also weel length and location within the upper unit. the end of 1994 was 48 mill . Sm3 o ut of a total rese rve of 69 mill . Sm3.The Ula main reservoir u nit is a fine to me d i um grai ned shal l o w marine sandstone wit ti typi cal pe rmeabi li ty i n th e range 50 m D -500 m D . The uppe r reservoi r uni t is fine grained witti rela t ively low permeability in the range 1 m D --10 mD . The permeabi l ity i n th e upper reservoir un it dec reases up wards .A t present, the Ula Field is operaled by 6 pe r iphera l wate r injectors witti 8 cresta l oil producers . 'ne Bistance betwee n the water injec t ors and the producers is typically in the order of 2 km .Witti the presen t well locations, the water floo d sweep efficiency and recovery is high throughou t the main reservoir uni t . The upper 'uni t, whic h contain s approximately 20 % of the total STOOI P , is howeve r poorly swep t by the curren t water injection scheme.WAG injection is reported to have a significant potential in North Sea reservoirs in generale . Simulation studiesZ and field trials3 indicates that the main WAG target is oil at the top of formation which is not recovered by water flooding . Horizontal Wells are reported to have a potential for increasing oil production rats and reduce coning in thin low permeable reservoir zones, compared to vertical wells4,7 .The paper discussen WAG injection and horizonta l ...