The Blake field, in the Outer Moray Firth, UKCS, is a shallow thin oil reservoir in the Captain sandstone formation. The initial subsea development consists of 6 production and 2 seawater injection wells tied back to the Bleoholm FPSO, 12 km away. The production wells are horizontal openhole completions with standalone sand screens whilst the injection wells are high-angle cased and perforated. The principal keys to the successful development of Blake were the placement of the production wells relative to the oil-water and gas-oil contacts and the efficiency of the water injection scheme. On completion and testing of the first seawater injection well, injectivity was found to be significantly less than expected and therefore had a potential material impact on the water injection strategy for the field. As a result focus was placed on understanding the key mechanisms influenceing well performance and to perform all necessary work to mitigate the effects in the second water injector. This work consisted of coreflood tests, diagnostic perforation surge flow modeling, perforation performance remodeling and well design and operational changes. From the coreflood tests it became apparent that formation fines mobilisation and migration was a major contributor to under performance. The surge flow modelling indicated that the underbalance applied when perforating the first injection well would have induced high surge flow rates potentially causing formation damage through rapid fines mobilisation; the underbalance having been designed to optimise perforation performance. As a result of this work the second seawater injection well was perforated with a lower underbalance set to limit the surge flow rate; this underbalance being significantly lower than the theoretical optimum required for perforation effectiveness. The initial injectivity testing on the second well has proved to be significantly better than for the first well. The paper outlines the diagnostic coreflood testing completed and how the results were applied together with the perforation surge flow modelling and perforation operational design to establish an operational strategy to optimise seawater injectivity on Blake; including well design changes. Background The Blake field is a shallow thin oil reservoir in the Early Cretaceous Captain Sandstone formation in the Outer Moray Firth, block 13/24, UKCS (see Figure 1). Blake consists of two basic reservoir structures; the channel sands and the flank sands. The current development exploits the channel sands, which are poorly consolidated and have porosities of around 28% and relative oil permeabilities of 1–3 Darcies. The saturated oil column is sandwiched between a gas cap and a large water aquifer. To maintain well deliverability at the required rates it was established early on that water injection would be required for pressure support. The principal keys to the success of the development were the need to delay the onset of gas and water production and so well placement with respect to the fluid contacts was critical combined with the performance of the seawater injection wells. This paper presents the methods used and the decisions taken to optimize the performance of the second seawater injection well following lower than expected performance in the first well.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper highlights the role which laboratory analyses together with in-situ monitoring surveys have helped in the scale management programme for the Dunbar Field, a very water sensitive reservoir situated in the South-Central part of the Shetland Basin, block 3/14. The major formation damage mechanism in Dunbar is that on production, the mixing of separate formation and injection brines drops out a sulphate scale within the near wellbore and wellbore itself. In order to solve this problem, TOTAL in conjunction with COREX (UK) Ltd., Aberdeen designed a laboratory programme to best mimic field scale treatments under reservoir conditions. Two separate water based scale inhibitors were assessed to evaluate their compatibility within the reservoir and identify any damaging mechanisms, which could result from their squeeze application. The interpretation of the permeability data obtained from the coreflood tests was aided by X.R.D. (x-ray diffraction), dry and cryogenic S.E.M. (scanning electron microscopy) and thin section analyses to determine the nature of the formation damage mechanism(s).The coreflood test results suggest that the major control on permeability impairment was the retention of a compound believed to be derived from the scale inhibitor which occurred as a thin film, hemispherical globules with a moderate wetting preference and/or irregular shaped globules with a high wetting preference. Retention of this substance reduced pore volume and narrowed pore throats, hence reducing permeability.In conjunction with the laboratory testing wellbore monitoring surveys were undertaken. Production and caliper logging tools were run to gather wellbore data and to give an indication of any decrease in wellbore diameter with time through sulphate scale drop out. Wellhead pressure and topside sampling of the connate/injection water mixture was monitored to determine if any scale precipitation was occurring and of what type.The evaluation of the laboratory data plus the information obtained from wellbore monitoring surveys were complemented by the more global recommendations issued by a task-force which includes, in particular, TOTAL's partner Elf Exploration UK PLC. It is on this basis that Total based its decision on the most suitable downhole scale management programme for the Dunbar Field.

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