UK North Sea

UK North Sea - Block 9/2b Kraken

• Kraken is a large heavy oil accumulation in UK North Sea East Shetland basin being progressed to development following successful appraisal and well flow test
• Based on the Operator’s numbers, best estimate contingent resources of 160mmbo gross (32mmbo net to Canamens) in Heimdal III formation
• Kraken has now had 5 appraisal wells drilled:
  · Latest 9/2b 5/5z well confirmed a tested flow rate of over 4,500 bbl/d with the potential to flow at 8,000 bbl/d
  · Crude gravity of 15o API – confirmed crude assay viscosity and PVT results are expected within 2-3 weeks
  · Preliminary log evaluation in well 5z indicates an average porosity of 38% and oil saturation of 90%
  · The 5z horizontal well confirmed reservoir continuity
• In addition to Kraken, Canamens also has interests in several near-field exploration blocks which include a number of identified prospects and leads
  · New Geostreamer 3D seismic has been shot over the whole area during 2011

North Sea Kraken field

The Kraken licence is located on the East Shetland Platform, west of the North Viking Graben. The structure is a large 3 way dip closed high on which oil was discovered in the Heimdal Sandstone system by the 9/2-1A well drilled in 1985 and successfully appraised by the joint venture’s 9/02b-2 commitment well in 2007, the 9/02b-4 well in 2010 and the 9/02b-5 well in 2011.The results of 9/02b-2, drilled  in October 2007, proved an oil column of at least 77m and an oil down to (ODT) 51 metres deeper than 9/2-1A. This appraisal well not only encountered oil bearing Heimdal Sandstone which correlated with the 9/2b-1A well (known as Unit III sands), but also penetrated an additional thin lower oil bearing Heimdal Unit I sandstone.A third appraisal well, 9/02b-3, drilled in September 2008, was located in a down dip area to the northeast of the discovery wells in order to investigate the upside (P10) resources. However, in this outlying area, the Heimdal Sandstone proved to be absent. Subsequent to the results of the 9/02b-3 well significant work was undertaken to de-risk Kraken and improve the understanding of the areal distribution of the reservoir.  The results of this work concluded that the Heimdal sands sourced from the west have been channelled southwards along the topographic low created by the Kraken fault. A CSEM survey confirmed an anomaly over both 9/02-1A, 9/02b-2 wells extending to the west of the fault and to the south of the 9/2-1A well.  This work culminated in the planning of the 9/02b-4 appraisal well which was spudded in August 2010.

Subsequent to the successful 9/02b-4 appraisal well the 9/02b-4z sidetrack was drilled. It successfully encountered oil bearing sands in both the Heimdal Unit III and Heimdal Unit II reservoirs. The Heimdal III had a true vertical net oil pay of 42 feet. The Heimdal Unit II had a true vertical net oil pay of 35 feet.  Evaluation of the Logging While Drilling (LWD) data indicated that average porosities in both units were very high, possibly exceeding 40%, with oil saturation of up to 90%. No OWC was encountered in either the Heimdal Unit III nor the Heimdal Unit II. The 9/02b-5 pilot well, spudded in July 2011, successfully encountered oil in the Heimdal III sand interval with a gross thickness of 44 metres, which exceeded predrill expectations. Preliminary log evaluation indicated a calculated net oil pay of 29 metres True Vertical Thickness (TVT) (the thickest net pay in the field to date), with average porosity of 38% and average oil saturation of 78%.  As anticipated, an OWC was not encountered at this location.On 26 September 2011, Nautical announced the results of the Kraken 9/02b-5Z horizontal well. The horizontal section of the well was drilled from 5,257 feet Measured Depth (MD) to a total depth of 7,260 feet MD, a horizontal displacement of 2,003 feet.  Preliminary log evaluation indicated a calculated net oil pay of 487 metres, with average porosity of 38% and average oil saturation of 90%. The logs indicated a continuous reservoir interval with a maximum pay thickness along the horizontal section of 37 metres feet true vertical thickness. The interval 5,257 – 6,724 feet MD was completed with sand screens and an openhole gravel pack. The estimated completed net pay was 1,287 feet which was then tested using an Electric Submersible Pump (ESP).  The well was put on production and cleaned-up at increasing flowrates for a total of 23 hours. A multi-rate test was then carried out including stable rates of 3,000 bbl/d for 12 hours and 4,100 bbl/d for 11.5 hours. The maximum stabilised rate achieved was 4,550 bbl/d. Production rates were constrained by the surface testing facilities. The productivity index at the end of the main flow period was 10 bbl/d/psi. Total oil produced during the test was 6,000 bbls. The water cut at the end of the main flow period was zero.

The fact that an Oil Water Contact (OWC) was not encountered in the 9/02-1A, 9/02b-2, 9/02b-4 and 9/02b-5 wells enhances the probability that the aquifer support will be through an edge water drive rather than a bottom water drive, which allows improved control over water production and injection thus optimising oil production and ultimate recovery from the reservoir. This is supported by geochemical analysis which indicates that, although the oil is biodegraded, it is not water washed implying the water leg is remote from the core of the structure.

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