The natural habitat of Legionella is the water environment. Little is known about their presence in groundwater in spite of the fact that many millions around the globe regularly rely on groundwaters. This pilot study was aimed at evaluating the occurrence of Legionella in groundwater samples (water and biofilms) collected from various sites. Water and biofilm samples from selected groundwater sources were examined for Legionella using culture media (selective and non-selective) and a semi-nested PCR assay. Innovative approaches such as immunomagnetic separation (IMS) in combination with cultivation and flow cytometry were also evaluated. The findings available thus far show that (a) Legionella could be readily recovered from groundwater samples by cultivation even though their numbers showed considerable variations, (b) surprisingly, the PCR methodology was not yet as sensitive as cultivation and (c) flow cytometry was not directly applicable on natural samples because of debris and the high number of heterotrophic associated microflora from which some members were likely to cross-react with the monoclonal antibody used for separation procedures (IMS).

Several downhole-sand-control failures in Okwori subsea oil producers triggered a significant overhaul of the downholesand-control method and a review of topside sand management. Because the eventuality of further downhole-sand-control failures in existing producers could not be ignored, a surfacesand-handling and -management facility was designed. For the future development producers, the downhole-sand-control method was re-engineered to increase its reliability. The initial multizone, fully selective sand-control-completion system, with expanded sand screens inside the casing, was abandoned. A revised openhole sand control was designed with similar completion selectivity. The new completion system implied a change in drilling practices, in reservoir drill-in fluid, and in filter-cake-cleanup techniques that required simultaneous engineering. These revisions were validated and implemented only a few months after encountering the first major sand-control failure. The Okwori floating production, storage, and offloading (FPSO) vessel was not expected to deal with sand production. Temporary sand traps were installed to minimize production downtime and to determine flow regimes that minimized sand production. Severe-service adjustable chokes were introduced to avoid valve erosion and stabilize production rates. Finally, a long-term topside-sand-management solution was designed and recommended for implementation.

After several downhole sand control failures in subsea wells,1 the Okwori field development underwent a significant change of direction both topside and sub-surface. Numerous constraints were taken into account and successfully managed: tight rig schedule, complex logistics, contractual issues, etc…. Downhole, the original multi-zone, fully selective sand control completion system hat included sand screen expanded inside casing was abandoned. A new system was designed that allowed similar selectivity but with open-hole sand control. The new completion system implied a change in drilling practices, reservoir drill-in fluid and cake cleanup techniques that required simultaneous engineering. These in-depth modifications were designed and implemented in a matter of months. Topside, the FPSO had not been equipped to deal with sand production since downhole sand exclusion was assumed to be reliable enough. A sand management study recommended a series of modifications that minimized production shut-down while safely handling the produced sand and oil. Test de-sanding using a temporary sand trap determined that sand produced from weak formations could be stabilized. Severe service chokes were installed allowing production at a constant liquid rate. Experience accumulated to date highlights the importance of appropriate planning and application of reliable technical solutions in subsea completions. Introduction Due to the high associated costs, subsea well development concepts are usually "interventionless". The initial costs of these wells are mainly due to the mobilization and day rates of sophisticated drilling rigs. To re-enter subsea wells, similar rigs are required, hence the prohibitive cost of well intervention1. This is the driver behind declaring these wells "interventionless". Once the "interventionless" nature of these wells has been stated, it is presented as a challenge to well engineering. To provide a reliable solution, the most robust techniques for construction and completion are required. As subsea wells are expensive, each completion must give access to sufficient reserves for economical justification. in sacked and compartmentalized structures, sufficient reserve per completion means complex wellpaths penetrating multiple targets as beads threaded into a necklace. When co-mingling is not an option and sand exclusion is required, these wells also become host of expensive jewelry. We know since 1948 2 that more equipment is run in a hole, the more can and will go wrong. Hence the interventionless concept becomes the "Quest for the Holy Grail" of engineering. This pursuit translates into a risk based search for the best engineering practices and proven technologies that are compatible with the project economics, combined with best practice implementation. Risks that could adversely affect the project must be mitigated and required measures must be implemented so that the project remains economical throughout its life. In the Okwori project offshore Nigeria, the Addax Petroleum and service provider personnel tackled all of these issues in record time. A Complex Subsurface Okwori subsurface is far from the traditional image of a big oil anticline into which wells are positioned to maximize recovery. Okwori field is a chaotic ensemble of superimposed hydrocarbon and water bearing pools that are separated by faults3. Today, more than 250 fault-dip closures have been identified, 59 of them with proved hydrocarbon content. For additional information, please refer to references 3 and 4. Figures 1 and 2 illustrate the highly compartmentalized nature of the field both laterally and in depth. To access these scattered reserves the development plan called for dispersed well-head locations, hence a subsea development with each well being individually tied back to a central floating production separation and offloading vessel (FPSO).

Auxiliary systems supporting pressurized water reactors (PWR) within commercial nuclear power plants are enclosed within a special ventilation (SV) zone that is isolated post-accident. Air within the SV zone is recirculated through carbon adsorbers, and discharged at a rate equal to the SV zone air infiltration rate. The SV zone relies on safety-related fan coil units (FCUs) to remove heat since air infiltration is kept to a minimum in order to reduce the spread of contamination. This paper discusses efforts undertaken to quantify area heat loads and FCU operating conditions within the SV zone, and transient analyses performed for loss of FCUs using the GOTHIC code.

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