During 10 years of production, crestal fluid pressures in the Magnus Field (UKCS) have dropped from 6650 psi to under 3500 psi leading to a two- to three-fold increase in the effective stress on the rock fabric. Petroacoustic measurements on cores indicate that this leads to a 12% increase in the acoustic impedance which, in theory, should be detectable using time-lapse seismic data. We analyse the difference between two 3D surveys shot over Magnus and relate this to dynamic changes in fluid pressure and saturation through time. The results demonstrate that, under certain conditions, fluid pressure changes may be detected in the reservoir and that fluid transmissibilities across faults can be deduced. Further, 4D seismic data may detect other dynamic processes, including thermal effects and cold water fracturing around injectors, and stress relaxation and fluid compositional changes around producers.

The Wytch Farm Oil Field, currently on plateau, produces up to 110 × 103BOPD, 17.6 × 106SCF gas and 725 tonnes LPG per day. Original reserves are 450 × 106BBL with a proven 230 × 106BBL oil equivalent remaining. The Triassic fluvio-lacustrine Sherwood Sandstone, at 1535mTVDSS (true vertical depth, subsea), is the largest and most prolific reservoir. Approximately half the reserves are in an offshore extension being developed by extended reach drilling (ERD) at step-outs of up to 10.1 km from onshore Poole Harbour. Projects to increase reserves, extend plateau and slow decline include: additional ERD wells; infill drilling; miscible gas injection; and pattern water flooding of the low nett: gross Upper Sherwood all whilst maintaining reservoir pressure.Reservoir description is central to realizing these opportunities for growth. Structural uncertainty has been reduced through acquisition of the first transition-zone 3D seismic survey in the UK. An extensive RFT (repeat formation test) and production log database has been acquired in the onshore and ERD wells. These dynamic data, together with static data from core and outcrop studies, and >21km of ERD formation evaluation logs, are used to develop a high-resolution, fluvio–lacustrine sequence architecture of the Sherwood. The deterministic model enhances predictability of flow barriers, baffles and high permeability intervals. This understanding of fluid flow and recovery provides the framework for economic evaluation, which, with clear communication of uncertainty across disciplines, is the key to successful management of the reservoir into later field life.

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Seismic 4D data has traditionally been acquired using repeat towed streamer surveys every 2–5 years. This is used to track fluid and pressure and has proved highly effective for influencing infill well locations and calibrating the reservoir simulator. Over the last 10 years the technology has evolved and is now relatively mature with several well documented case-studies demonstrating value of 3–5% reserves increase in post-plateau oil fields with a strong fluid response (1). However, the long elapsed time between surveys limits its value in Reservoir Management where we would like to use time-lapse seismic to monitor the pressure field and the fluid flood fronts and therefore make decisions which maximise the sweep conformance and achieve ‘technical limits’ rate and reserves. To do this, seismic data needs to be acquired at a frequency consistent with the timescale on which the decisions are made. Thus monitoring gas movement to minimise gas production in oil field may require seismic surveys every 3–6 months whilst providing data useful for optimising Base Well Management decisions on reperforations, restimulations, water shut-off and injection rates may benefit from seismic data every few months or even weeks. As a first stage towards active management using "seismic surveillance", and specifically to aid in waterflood management, BP has installed a permanent seismic array over 70% of the Valhall field. The array cost $45million but the results have been technically spectacular (2, 3, 4). Learnings from this experience are still evolving but already cover aspects of reservoir management, infill drilling, Base Well Management, flow performance prediction and surveillance including the use of "Seismic PLTs" (2). Following on from this success, BP is looking at the next wave of field applications as an integrated part of its FIELD OF THE FUTURE programme (5). Plans are now at an advanced stage to take forward two new projects in 2006 and several more are being discussed for application later this decade. 1. Seismic Surveillance in the FIELD OF THE FUTURE 1.1. Concepts of the FIELD OF THE FUTURE Rapid changes in digital technology are revolutionising the ways in which we acquire and process data and are improving the quality and efficiency of decision making. Through the application of these digital technologies, both new and existing, BP aspires to operate its assets at the technical limit of efficiency, recovery and cost. To make this aspiration a reality, BP has implemented a programme called FIELD OF THE FUTURE (1). The scope of this programme covers development and deployment of technology and business process solutions to most aspects of oil and gasfield operations - from reservoir to export, in both mature and new fields, onshore as well as offshore. 1.2. Remote Performance Management and Optimisation Remote Performance Management includes technologies for well/reservoir and facilities monitoring and is currently an area of focus in BP (6, 7). A large part of this activity is to do with developing and applying new tools for managing and post processing real time data. Optimisation needs to be carried out in a variety of different technical areas and at many different timescales. In the subsurface, it is about developing improved methods for maximising production and reserves. The elements required for an effective decision can be described by the OODA cycle. Here four components are identified: Observation, Orientation, Decision and Action.

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