TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFor BP the North Sea is an important mature basin which produces around 15% of the company's total global production of around 4000 mboed. However, like many mature basins sustaining a profitable and competitive future is challenged by the overall decline in oil and gas production rates, increasing trend in unit operating costs, the integrity and operability of the ageing infrastructure and the changing demographics of the work force. In this perspective, North Sea has become a key exemplar that illustrates how BP's FIELD OF THE FUTURE programme can help to meet numerous challenges in the management of mature areas.To help manage and reduce the negative impact of these business challenges BP is implementing a North Sea regional FIELD OF THE FUTURE Technology programme. The vision over the next 5 years is to deploy FIELD OF THE FUTURE technologies at scale across most BP operated fields with the aspiration to improve overall production by 5% and reduce operating cost by 10%.For the North Sea mature assets the main focus is around four technical projects: Advanced Collaborative Environments (ACE); Real time data monitoring and surveillance; Advanced control and optimization; Automation and remote control. From the outset BP has discovered many challenges in deploying and implementing at scale across a region. This paper will share some of the key challenges and insights involved in implementing at scale the technical projects through the appropriate process, organisation capability and technology across the region.

First production from the Viking fields began in 1972 and at its peak a total of 13 platforms produced at rates up to 930 million cubic feet per day from 20 wells and was supplying 12% of the United Kingdom's natural gas requirements. In addition, several prospects were drilled in the early 1970's but, due to disappointing results, were viewed as un-economic and consequently were not pursued for development. Since discovery in the late 1960's of the Viking A and B fields and associated satellites, exploration and appraisal within the Viking contract area has identified five possible new gas accumulations named the Viking Extensions. Appraisal of these extensions commenced with the remapping of the Viking contract area with proprietary 2D seismic data acquired in 1983 and 1987, supplemented with traded seismic data from adjacent block operators. However it was only the re-negotiation of the gas sales contract and the removal or the Gas Levy in 1992 that provided favourable marketing conditions for the development of additional Viking gas production and initiated the current appraisal programme for remaining reserves. This programme began with acquisition of a 3D seismic survey in 1993 and these data and subsequent drilling have resulted in very promising initial results. It is expected that as this latest evaluation of the Viking extensions and remaining exploration prospects reaches it's full conclusion, between 730 and 1000 Bcf or additional gas reserves will have been realised. This will provide the opportunity for many more years of renewed life from one of the oldest producing areas in the North Sea. Viking Field History The Viking field area is located in the gas basin or the Southern North Sea approximately 140 km offshore from the Lincolnshire coast of England (Fig. 1). The blocks covered by the Viking area include 49/12a and 49/16 and 49/17 (Licence P033) and were originally awarded to Continental Oil Company in Licensing Round 1 in September 1964. Current licensees are the operator Conoco (U.K.) Limited, and B.P. Exploration each holding a 50% equity. Producing Reservoirs. Nine accumulations of gas, Viking A, B, C, D, E, F, G, Gn, and H have been discovered and put on production (Fig. 1) since the first well, 49/12-1 was drilled in 1969. All reservoirs comprise the Lower Permian Leman Sandstone Formation of the Rotliegendes Group with producing zone porosities and permeability's ranging from 7% to 25% and 0.1 mD to over 1000 mD), respectively. Two central gas gathering complexes, A and B, receive gas from the nine accumulations. Gas is gathered at the B complex from its own field and satellites C, D, E, G and H and piped 11 kilometres to the A complex through a 24 inch diameter pipeline. It then enters the Viking Transportation System's (VTS) 28 inch pipeline to be transported onshore to the Theddlethorpe gas terminal on the Lincolnshire coast. All wells in the A and F reservoirs were permanently abandoned in 1995. Initial gas in place (IGIP) and Reserves. The IGIP for all Viking area producing fields has been estimated at 3,230 Bcf or which approximately 2,750 Bcf have been produced (as of March, 1995) reflecting a recovery of 85%. The three largest fields have produced 76% or the total reserves from the A (970 Bcf), E (620 Bcf) and C (515 Bcf) reservoirs whilst the B, H and G reservoirs have produced an additional 17 % and the D, F and Gn represent the remaining 7%. Geologic Setting and Stratigraphy The Leman Sandstone consists of stacked aeolian sands ranging in thickness from around 500 to over 800 feet. These were deposited under arid conditions in a large, predominantly east-west trending basin, initiated by thermal subsidence at the end of the Variscan orogeny.

Field A is a giant field consisting of many sub reservoirs in Abu Dhabi offshore environment, having produced for 50 years mainly through peripheral water injection. The filed considered in this study is planning to build the long-term development plan aiming to extend production plateau by a further 25 years through infill drilling and water flood enhancement. This paper will describe an approach for optimizing the number and type of drilling centres required to enable the development plan to be flexible in design to accommodate a number of infrastructure, facilities, drilling and subsurface constraints. The proposed reservoir development scheme is to progressively expand from the on the current peripheral water injection to enhanced water injection phase requiring line drive and pattern flooding. The project requires integration of around 180 new wells to be drilled with the associated injection and production facilities into an existing brown field complex with more than 1000 wells, kilometres of pipelines including well head towers and artificial islands. In addition the project requires having flexibility to expand for later field development schemes that could include further infill and EOR phases. The key challenge for the development plan is to assess the impact of drilling feasibility and the number of drill centres within the constraints of the existing brown field infrastructure and how it impacts on the production profiles, cost, project feasibility and value. Analysis and selection of number and location of drilling centres are essential requirement for finalizing the optimal development. An integrated subsurface, surface and drilling feasibility assessment analysed several different drilling centre scenarios involving various combinations of artificial islands and well head towers. Different drilling and completion duration were calculated based on drilling complexity and feasibility for the different development plan scenarios. The impact on the production profiles were assessed based on reservoir simulations using the well delivery timing for each scenario. The final screening assessment of the different field development scenario included inputs and constraints from infrastructure, facilities, sea-bed complexity, HSE, flexibility and project economics. The major findings are followings: (1) field development planning requires integration of different functions and disciplines early in the project phase before entry into Select stage, (2) important to test the feasibility of drilling and its impact on the field development concepts and production profiles, and (3) the results indicated the preferred development plan that best meets the objectives is based on a combination of artificial islands and well head towers. The preferred development plan will utilizes a novel combination of artificial islands and well-head towers that enables flexibility and expandability to meet the development plan objectives of extending the production profile and provide a foundation for long term asset replacement.

No abstract

No abstract