Abstract

Oseberg 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 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 in order to identify the scaling risk for each producer. From this 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 (our experience with treatment using chemical injection lines, injection of scale inhibitor into the gas lift system and squeezing).

Overview of Oseberg Sør Field

Oseberg Sør field began first oil production in 2000 and has continued to expand with an active drilling programme through to 2008 and beyond. The field currently comprises 16 producers of which 13 are platform wells and 3 producing from subsea templates, Figure 1. These wells are supported by a combination of Utsira aquifer water and WAG (water alternating gas) injectors. The decision to use the Utsira water (Table 1) rather than seawater for reservoir support was made early in the field planning phase. As a result, sulphate scaling of the near wellbore and tubing is eliminated and the only concern is carbonate scale forming in the upper tubing.

The Jurassic reservoir targets include channel deposits of uncertain connectivity, deltaic sequences with associated turbidites and deepening upwards sequences going to deep marine, pelagic deposits. N-S trending faults are common and are associated with the formation of the Viking Graben. These faults can compartmentalise the field into reservoir units of distinct formation water composition, temperature and pressure characteristics. The typical reservoir temperature is 107°C and initial reservoir pressure was approximately 290bar (ranges between 150 bar to 300 bar).

Well geometry is complex and is controlled by reservoir and structural geology. A typical Oseberg Sør well is horizontal but the well pathway can be tortuous as it passes from one structural unit to the next.

Development of a Downhole Scale Management Strategy

The rationale behind the development of a scale management strategy for Oseberg Sør was to evaluate the risk for scale generation downhole with respect to asset integrity and the economic impact on oil revenue generation. With regards to asset integrity the principal area of focus was CaCO3 scaling of the downhole safety valve with implied platform security issues. These safety valves are tested in general once per month depending on the scaling severity. Failure of the valve due to scale results in significant downtime with enormous consequences for lost revenue. In consequence, the approach of Hydro on Oseberg Sør has been to perform a scaling risk analysis to identify where in the system the problems could occur and on the basis of this pre-emptively treat the wells. Various treatment strategies have been considered, technically evaluated and costed. The choice of strategy selected was well dependent and was related to completion type, well geometry and the effectiveness of product deployment on scale mitigation. With respect to the scale inhibitor deployed, a key aspect of the strategy, and in line with Hydro's policy, was the selection of chemicals that showed minimal environmental impact.

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