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.

The United Nations Commission on the Limits of the Continental Shelf is expected to play an essential role in delineating the rights of the Arctic states to seabed resources in the Arctic Ocean. In this article, the authors look to the effect of scientific discourse on Commission authority. The authors argue that in addition to the conferral of its authority by the United Nations Convention on the Law of the Sea, the Commission draws its authority in the Arctic from the way its regulatory frameworks, aimed at containing or closing off disputes about jurisdiction and sovereign rights, correlate with discursive practices used by transnational networks to reach scientific agreement.

The Prudhoe Bay field is the largest accumulation of oil and gas in North America. Because of the size, and the fact that it produces from multiple mechanisms including lean gas cycling, gravity drainage, pattern waterfloods, pattern MI / WAG injection and gas cap water injection for pressure maintenance, a full-field model (FFM) with a rigorous surface pipeline network and facilities model is necessary to answer many depletion planning questions and to evaluate the benefits of largescale or field-wide projects. With additional reservoir description data and production history, the opportunity existed to use current software and hardware to build an improved model. In 2005 an effort began to build a new FFM, including both geocellular and simulation models. This paper discusses the issues addressed at the start of the rebuild in preparation for the history match, the history matching effort, and the transition to predictive runs. Preparation for the history match included setting the objectives for the model, the grid design, generating pseudo relative permeability curves, and implementing parallel processing. The key parameters and data used to obtain a history match are discussed, as are the issues and methodology utilized in constructing predictive cases. Some of the key interactions with the parallel geologic model construction are also discussed. It was demonstrated that a compositional model with approximately 1 million active cells and over 650,000 non-neighbor connections associated with over 1000 structural faults could be run and history matched in a commercial parallel reservoir simulator in a reasonable time. With approximately 25 BSTB of oil, 46 TSCF of gas in place, and over 2500 historical wells, the challenge of building a fullfield model for a field the size of Prudhoe Bay was daunting. A project of this magnitude required excellent up-front preparation and cross-discipline coordination. Introduction The current full-field simulation model of the Prudhoe Bay Field was built in 1995. Due to the size of the field, as well as hardware and software limitations at that time, the simulation grid was very coarse with 60-acre (1617ft X 1617ft) grid blocks, making areal discretization of faults, wells and waterflood/MI injection patterns problematic. As the oil column thins and remaining targets shrink, a model with greater resolution for future project evaluations was required. The decision was taken by the major partner companies to build a new simulation model based upon a new 3D geological and petrophysical model, to take advantage of better hardware, software and workflows. The rebuild effort started in January, 2005. Initially the focus of the work was on the geocellular model build. However, many aspects of the simulation model had to be set before final delivery of the static description to avoid delay of the history matching process. This paper discusses the work that was done in preparation for the history match and the history matching process and results. There is also discussion of the transition and calibration from history to predictive mode.

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Obtaining a core behind the flood front appears to be the most appropriate way to directly measure residual oil saturation. Conventional analysis based on resistivity logs requires the water salinity to be known. As the pore space behind the flood front contains a mix of formation, aquifer and injected water with significantly different salinities, water saturation calculated therefore will have a large uncertainty associated with it. While e-line NMR and other conventional logs can give indirect estimates of residual saturation without any calibration, Direct measurements to overtake this challenge can only be carried out on a core. In this paper, we present a core behind flood front that was acquired in a BP Angola field. The core analysis provided a direct measure of the residual oil saturation throughout the cored interval providing information about vertical sweep efficiency as well as the value of the residual oil saturation. The value added through the acquisition of core was considered to have reduced the risk of inefficient oil recovery by: Understanding the efficiency of the sweep in channel edges Understanding rock properties behind the flood front Direct determination of residual oil saturation. Assuring reserves in place and Remaining Reservoir management strategy by Water injection strategy and Improve understanding of reservoir will lead to better depletion management – targeting of infill wells. Determine tertiary oil recovery techniques. Aid calibration of water and oil saturations in simulation models. Assist with production performance prediction and reduced surveillance. Opportunity to cut a behind the flood front core in channel edges facies (low NTG).