fax 01-972-952-9435. AbstractOseberg Sør field, operated by Hydro Oil & Energy, is situated 130km west of the Norwegian coast on the eastern flank of the Viking Graben structure. It consists of fault bounded structural units of varying geological complexity. Within these units the reservoir intervals are of moderate to poor quality and can exhibit strong contrasts in permeability and formation water composition. Reservoir pressure support is provided by combined injection of gas and Utsira aquifer/produced water. The wells are a combination of platform and subsea and include extended reach horizontals with complex geometry and lesser numbers of vertical well.Coreflooding has been undertaken on material from the major producing intervals (Ness, Middle & Upper Tarbet and Upper Jurassic). This coreflooding has been used to assess potential formation damage resulting from application of oil based mud or scale inhibitor squeeze treatment. In all instances, the major cause of formation damage was the mobilisation of kaolinite that can form up to 20wt% of the bulk rock and occurs in all producing intervals. Coreflooding demonstrated that even at very low flow rates (30ml/h) permeability was reduced by up to 99% during initial plug saturation and before the onset of treatment. Modification of the coreholder allowed multi-port permeability measurements to be made that gave an indication of the depth of damage.Field evidence only gives an indirect indication of the effect of kaolinite mobilization on well productivity. For example, a gradual reduction in well productivity has reversed after squeeze treatment. This gradual decline is possibly a result of the migration of kaolinite during well inflow with consequent reduction in permeability. Squeezing could have caused the dispersion of kaolinite away from the near wellbore with an increase in well productivity.Given the adverse results obtained from coreflooding due to kaolinite mobilization, significant effort has been directed towards identify methods by which to reduce its impact, through incorporation of clay stabilizers in scale inhibitor squeeze treatments and remedial treatments using mud acid stimulation. Laboratory results of these evaluations will be presented (mud acid coreflooding results were not available at the time of writing).While the occurrence of kaolinite on Oseberg Sør has potentially reduced well inflow performance, it has had a positive influence on scale inhibitor squeeze lifetimes. A field example will be given to show this.

TX 75083-3836, U.S.A., fax 01-972-952-9435.

During the last decade, intelligent well completions have evolved to become engineered solutions widely used for both monobore and multilateral horizontal wells. However, a clear understanding of zonal or lateral branch flow contributions still remains an issue. Several SPE papers covering the issue have been published recently. This paper presents the engineered solution for a TAML level 5 dual-lateral horizontal well that was drilled and completed in the Oseberg Sør field in December 2005. The solution combines hydraulic flow control valves with advanced downhole two-phase flow and density measurement provided by a Venturi-based flowmeter with a gamma ray source and detector. Real-time data were used to optimize the settings of the downhole chokes to obtain a balanced production from the two horizontal wellbores. The completion provides the capability to control and measure, in real time, flow contributions from both laterals and is the first installation of its type. This capability is critical for production and reservoir optimization. Additional value of the technology is demonstrated by the analysis of acquired downhole data. Productivity Indices are obtained for each of the two laterals without any production loss associated with shutting down the other lateral branch. Data analysis indicated a decrease of the Productivity Index for one of the two horizontal wellbores. The successful installation of the two-phase flowmeter in an intelligent completion is a significant milestone corresponding to the general trend in the industry to improve inflow control and the understanding of flow contributions in multilateral wells. This solution for flow control and measurement can be applied effectively in both multilateral wells and monobore wells designed for commingled production from different reservoirs where accurate production allocation is a critical issue. Introduction Intelligent completions have developed over recent years with increasing functionality to meet specific applications. Norsk Hydro has been particularly active in implementing innovative intelligent completion solutions to meet its objectives.1 This implementation commenced in 1998 with natural gas lift on the Troll field using hydraulic gas lift valves. For the Fram Vest field, an innovative natural gas lift completion was implemented using this field proven technology repackaged for a more efficient, safe, and environmentally friendly completion system. Several intelligent wells were completed on the Oseberg field with long reach, highly deviated wells having flow control of two to three zones with hydraulic flow control valves. Norsk Hydro then turned its attention to flow control of multilateral wells. A completion solution integrating flow control of the lateral and main bores together with natural gas lift was implemented on the Troll and Vestflanken subsea fields. There was a growing understanding that downhole production monitoring was needed in order to draw the full benefit of the intelligent multilateral completions. This resulted in the installation of Schlumberger downhole flowmeter in Norsk Hydro multilateral well F-29 on the Oseberg Sør field. The well was completed with flow control of both the main bore and lateral bore with flow measurement of the main bore. Applied downhole two-phase flow and density measurement principles were the same as for BP Harding well PN1.2 Oseberg Sør Field Description The Oseberg Sør field, operated by Norsk Hydro, is situated 130 km west of the Norwegian coast. The main oil-producing reservoir is the Tarbert formation within the Brent group, which is of variable reservoir quality with permeabilities ranging from 1 D to 1 mD. The 33 API oil was initially slightly under-saturated, but some parts of the field have been heavily depleted. The field comprises several structures that are drained by extended reach and horizontal oil production wells. The development includes both platform wells and two subsea templates that are tied back to the platform. Reservoir pressure is supported by water and gas injection.

Summary Oseberg Sør field, operated by Hydro Oil & Energy, is situated 130 km west of the Norwegian coast on the eastern flank of the Viking Graben structure. It comprises a sequence of fault-bounded structural units of varying geological complexity. Within these units, the reservoir intervals are of moderate to poor quality and can exhibit strong contrasts in permeability and formation water composition. Reservoir support is provided by combined injection of gas and Utsira aquifer water. The wells are a combination of platform and subsea and comprise extended reach horizontals with complex geometry and lesser numbers of vertical wells. Detailed scale predictions have been performed to identify the scaling risk for each producer. From these, it was identified that the major risk to well performance and integrity was CaCO3 precipitation in the upper tubing with potential failure of the downhole safety valve. The risk varied from negligible to severe and reflected the variable composition of the produced water and well operating conditions. The scale predictions provided the basis for a technical and economic evaluation to identify an appropriate scale-management strategy for Oseberg Sør. For those wells completed with downhole chemical injection lines, the option to use these for scale inhibition was considered cost effective. In other wells where this option was not available, scale inhibitor injection into the gas lift system or squeezing using a viscosified treatment was considered viable. The paper will provide the technical and economic reasoning for the scale-management strategy selected along with field case histories for each treatment type (i.e., experience with treatment using chemical injection lines, injection of scale inhibitor into the gas lift system, and squeezing).

TX 75083-3836, U.S.A., fax 01-972-952-9435.