Important objectives of the MSc courses in Petroleum Engineering and Petroleum Geoscience at Imperial College are educating students in the work flow concepts now prevailing in the oil industry, and producing petroleum professionals who are specialists in their respective fields but are trained to work effectively in multi-disciplinary teams. One of the tools used to meet these objectives is a group project using data from the UKCS Maureen field and made available by Phillips Petroleum (UK) Ltd. This paper describes the rationale for developing a group project exercise based on real field data, the approach used to develop the group projects and the lessons learned. Introduction Over the last ten years, most oil companies have reorganized from functional departments (geology, geophysics, drilling, petrophysics, reservoir engineering, production, etc.), into multi-disciplinary asset teams, which include all the specialists that are required for managing a reservoir. This follows from the recognition that the reservoir management process requires close cooperation between many different disciplines. These changes, however, have yet to reach most universities, which still teach each petroleum discipline as a separate subject, mainly because the various skills needed reside in separate departments. Teaching Reservoir Management as an integrated process requires a multi-disciplinary, coordinated effort. Such a curriculum has been implemented at Imperial College in London, UK, within the Centre for Petroleum Studies. The role of the Centre, which is part of the T.H. Huxley School for Environment, Earth Sciences and Engineering, is to coordinate all petroleum related activities at Imperial. The MSc courses in Petroleum Engineering, Petroleum Geology and Petroleum Geophysics have been reorganized to give students the required understanding ofthe fundamental concepts of reservoir characterization, reservoir modeling, reservoir simulation, and field management;the links between the various types of data; andthe processes for integrating and processing all available information. Formal lectures are complemented with a Group Field Development Project. This project concerns the evaluation of part of a license block in the UKCS and the preparation of recommendations for development through abandonment. It consists of a competitive reservoir evaluation/development exercise carried out by groups of about five/six students. Recommendations follow a format similar to that of the former ‘Annex B’ document for the UK Department of Trade and Industry. The Group project is currently based on the UKCS Maureen field.1–4 The Reservoir Management Process5 Reservoir management is the application of available technology and knowledge to a reservoir system in order to control operations and maximize the economic value of the reservoir. It is about making the best possible decisions that will enable a company to meet specific objectives, and implementing these decisions. The ability to make the best possible reservoir management decisions relies mainly on the ability to predict the consequences of implementing these decisions and to evaluate the associated uncertainties. This in turn depends on the ability to model the expected behaviors of the reservoir system. The complete process, schematically represented in Fig. 1, includes four stages: Reservoir Characterization, Reservoir Performance, Well Performance and Field Development. Full details are shown in Fig. 2.

The 48!l7b-G2 well was the second and final development well on Guinevere; a UK Southern North Sea Rotliegendes gas field.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Early Aptian carbonates of the Mauddud Formation form giant hydrocarbon reservoirs in North Kuwait. Reservoir description and distribution of rock properties in 3D space are challenging due to inherent reservoir heterogeneity. A robust depositional model driven by sequence stratigraphy, petrophysics tuned to dynamic data and innovative static modeling techniques were used to characterize this complex reservoir.The Mauddud carbonate sedimentation took place in a low angle ramp setting. The basal part of Mauddud consists of shales and low energy carbonates deposited in a transgressive systems tract. The main reservoir was deposited during the subsequent highstand systems tract. High-energy inner ramp grainstones preserve the best primary porosity and permeability. Reservoir quality deteriorates in mid ramp to inner ramp wackestones and mudstones.Diagenetic carbonate concretions destroy porosity and permeability. It is more pronounced in mud-rich packstone / wackestone fabrics. Early hydrocarbon emplacement has terminated concretion growth in crestal areas of the field whereas concretion formation and subsequent reservoir degradation continued in the water leg through late diagenetic stages. Rudistic floatstones, radially fractured concretions and small-scale fractures in low-porosity brittle rocks are the main thief zones in the reservoir.Through the integration of core, openhole logs, production logs, and pressure transient analysis, a deterministic permeability model has been developed that characterizes the reservoir. Logs have been reprocessed to identify zones of secondary porosity (enhanced permeability) and fractureprone zones. Porosity-Permeability transforms for matrix properties and fracture-prone intervals were developed. This methodology results in log-derived permeability profiles that match production log profiles and well test Kh estimates.A fine Geological model with 85 layers and 2.5 million cells has been built to capture the primary depositional units. The horizons bounding the flow units are major flooding surfaces. The lithofacies associations have been modeled as composite objects restricted to facies belts. As porosity was observed to be decreasing towards the flank, trend modeling has been used to model the effective porosity. Another geological model with 166 layers was built to capture the small-scale heterogeneity caused by vuggy zones and fractures. The vugs and fractures have been modeled as objects restricted within an area demarcated by poorer seismic coherence. The Matrix permeability was enhanced by vuggy permeability and fracture permeability.The paper describes the challenges in reservoir description and static modeling of this complex reservoir in detail.

Asphaltene deposition in the reservoir, wellbore and facilities has long been recognized as a problem in the Marrat reservoir in the Magwa field, Kuwait. One option of avoiding asphaltene problems in the reservoir, including the near wellbore region, is to maintain reservoir pressure and flowing BHPs above the asphaltene onset pressure (AOP). Given that there is a large pressure difference between AOP and the bubble point pressure and that natural flow is possible at pressure well below AOP, there may be economic benefits in operating the reservoir at pressures below AOP. Benefits relate the reduced and delayed costs of water injection facilities. There may also be some additional recovery related to fluid expansion. Potential problems relate to possible adverse changes to relative permeability due to asphaltene related wettability changes, productivity impairment due to near well-bore asphaltene deposition and increased asphaltene problems in the wellbore. The second and third of these potential problems have been assessed by a field trial. This paper describes the selection of a candidate well and the design of a field trial to assess these problems. The selected well was produced first with FBHP well above the AOP. Asphaltene deposition in the tubing was monitored, fluid samples were taken and pressure transient tests were performed to diagnose well inflow performance. No decline in well productivity was seen in this period. Asphaltene deposition in the tubing was a problem and the well required cleaning during this period. The well was then produced at high rate, with flowing BHP well below AOP and a similar surveillance program was carried out. Finally the well was returned to low rate production. Analysis of the data from the high rate and subsequent low rate production periods indicated that there had been a limited decrease in well productivity. These data also showed that asphaltene deposition in the tubing was less of a problem during the high rate test than during the preceding low rate test.

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