Biogeographic patterns have been demonstrated for a wide range of microorganisms. Nevertheless, the biogeography of marine viruses has been slower to emerge. Here we investigate biogeographic patterns of marine cyanophages that infect Synechococcus sp. WH7803 across multiple spatial and temporal scales. We compared cyanophage myoviral communities from nine coastal sites in Southern New England (SNE), USA, one site in Long Island NY, and four sites from Bermuda's inshore waters by assaying cyanophage isolates using the myoviral g43 DNA polymerase gene. Cyanophage community composition varied temporally at each of the sites. Further, 6 years of sampling at one Narragansett Bay site revealed annual seasonal variations in community composition, driven by the seasonal reoccurrence of specific viral taxa. Although the four Bermuda communities were similar to one another, they were significantly different than the North American coastal communities, with almost no overlap of taxa between the two regions. Among the SNE sites, cyanophage community composition also varied significantly and was correlated with the body of water sampled (e.g. Narragansett Bay, Cape Cod Bay, Vineyard Sound), although here, the same viral taxa were found at multiple sites. This study demonstrates that marine cyanophages display striking seasonal and spatial biogeographic patterns.

Summary Production optimization requires a clear understanding of subsurface conditions throughout the fields life. The recent move from 2D description techniques to fully numeric 3D models with high end graphics display capabilities is having a significant impact on development planning and monitoring activities. The focus here is on the perceived benefits and challenges of using 3D models to optimize production with examples of integrated 3D static and dynamic modelling activities carried out on fields which were undergoing appraisal, development and facing abandonment. Case 1 (appraisal) illustrates how the integrated use of 3D modelling and simulation technology during primary development enables PE's to rapidly construct alternative reservoir models and quantitatively evaluate the impact of various uncertainties. This approach optimizes production by facilitating fast-track developments, design of robust development schemes incorporating optimized well paths and providing quantified justification for appraisal expenditure. Case 2 (mid field life) illustrates the benefits of using 3D modelling technology to integrate static and dynamic field data, geological knowledge and scenario analysis concepts to locate bypassed oil and optimize infill well trajectories. History matching offers the geologist valuable feedback on the robustness of the geological model including aspects such as the size and orientation of reservoir sands. The relative impact of various uncertainties can be quantified and development schemes optimized. Case 3 (end field life) illustrates how even in very mature fields which are facing abandonment, 3D modelling technology can facilitate data integration with subsequent cross-discipline interpretation leading to the successful planning and drilling of horizontal side-tracks to develop by-passed oil. In all cases the technology used allows sophisticated 3D models of the subsurface to be built via integration of diverse data types and geological knowledge. The resultant models can be rapidly upscaled for dynamic simulation with model optimization via iterative feedback from the simulator being easily achieved. The facility to plan and "drill" wells in the 3D volume enables development scenarios to be optimized both in terms of well trajectory and multi-disciplinary teamwork. Introduction In broad terms, optimization of hydrocarbon production aims to maximize the value of an asset or resource; i.e. production optimization is directly related to the economic aspects of managing field development. The concept of the field life cycle, running from discovery through appraisal and development to abandonment makes a useful framework for exploring how 3D modelling technology has already contributed to increasing the economic value of hydrocarbon resources in the Shell Group. During the early phase of a field's life, activities are aimed at designing a flexible development plan which is economically robust to potential downsides but can also rapidly respond to upside opportunities. However, petroleum engineers have minimal information about the reservoir and consequently need to evaluate the potential impact of numerous uncertainties on the development activity. The focused use of integrated 3D reservoir modelling and simulation technology to rapidly evaluate alternative development scenarios is proving to be a successful way of managing these uncertainties. During the later phases of a field's life, when production has dropped-off plateau, activities are aimed at identifying the location of poorly drained and bypassed hydrocarbons and quantifying the economic benefits of additional investment to improve offtake rates and maximize recovery. Increased field data lessens uncertainties, but PEs need to be able to compile all the information into cohesive subsurface models. This is facilitated by the close linkage of 3D modelling technology with dynamic reservoir simulators which together provide a powerful reservoir management and development planning capability. In the late stage of the field's life, activities focus on quantifying the value of the remaining asset with a view to late stage development activities or divestment/abandonment decisions. Mountains of variable quality data, combined with an often long, complex development history provide a considerable challenge, both in terms of data management and the visualization and recognition of opportunities. 3D modelling technology allows integration and QC of diverse data, facilitating multi-disciplinary team efforts to identify, plan and screen of end field life activities.

The Brent Field was the first discovery in the northern part of the North Sea, and is one of the largest hydrocarbon accumulations in the United Kingdom licence area. There are two separate major accumulations: one in the Middle Jurassic (Brent Group reservoir) and one in the Lower Jurassic/Triassic (Statfjord Formation reservoir). The Brent Field lies entirely within UK licence Block 211/29 at latitude 61~ and longitude 2~ the adjacent Brent South accumulation extends into Block 3/4A. The water depth is 460 ft. The Brent Field discovery well was drilled in 1971, and was followed by six further exploration and appraisal wells. Seismic data over the Brent Field has been acquired in four separate vintages. The latest acquisition in 1995 allowed detailed mapping of the complex eastern margin of the field for the first time.The Brent Field is developed from four fixed platforms (Alpha, Bravo, Charlie, Delta) installed between 1975 and 1978. Production commenced in 1976 and, for the first 22 years of field life, the platforms provided production, water injection and gas injection facilities for both the Brent and Statfjord Formation reservoirs. The Brent South accumulation is produced via the Brent Alpha platform, through sub-sea tie-backs and extended reach wells. In 1992, the decision was taken to depressurize the Brent Field to recover an additional 1.5 TSCF of gas and 34 MMSTB of oil, extending the field's life by 5-10 years. In January 1998, water injection into the main field was stopped and depressurization of the field initiated. As of January 2000, a total of 220 platform wells and three sub-sea wells (173 producers, 50 water injectors) have been drilled in the Brent Field.The original oil/condensate-in-place is currently estimated at 3.8 MMMSTB, and the estimated original wet gas-in-place is 7.5 TSCF. Total ultimate recovery for all reservoirs is expected to be 1988 MMSTB oil and condensate and 6000 BSCF gas. Cumulative oil and net gas production, as of 1st January 2000, was 1875 MMSTB oil and 4196 BSCF gas.This paper summarizes the current understanding of the field based on acquisition of new 3D seismic data, 130 new wells, detailed structural and sedimentological modelling, development of the complex crestal part of the field and finally, the initiation of an extensive brown field re-development project to depressurize the reservoir.

This paper was prepared for presentation at the 1999 SPE Offshore Europe Conference held in Aberdeen, Scotland, 7–9 September 1999.

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