The Athena oil discovery is located in the Outer Moray Firth, lying 18 km west of the Claymore and Scapa fields and associated production facilities. Ithaca currently holds a 22.5% interest in block 14/18b within which lies the Athena oil discovery. 24.4 million barrels of 2P reserves (gross) have been estimated for Athena by Spoule Associates at their 2009 year end review.

Vigorous work now focuses on a commercial solution to developing Athena in an environment of escalating oil price and re-based engineering costs.  Plans are ongoing to develop the field in a staged manner; initially by completing the 3 existing development/appraisal wells already drilled and drilling a further water injector well to allow first oil.  The second stage will be two more production wells after first oil to complete the core development of the field.   A range of FPSO technologies are being examined for their applicability on this project and this could significantly reduce costs. However, the neighboring Claymore facility still remains a viable option for Athena tieback and processing depending on capacity constraints. FDP approval is now targeted for end H2 2010 and submission awaits the conclusion of subsurface and engineering studies.

Two wells previously drilled on block 14/18 tested oil. Well 14/18-12 tested 1,302 bbls/d from the Upper Jurassic sands (not included in Athena) while well 14/18-7 tested 847 bbls/d from the Lower Cretaceous Leek sands, the Athena reservoir interval. The first well operated by Ithaca, 14/18b-15, encountered 320 feet of gross and 241 feet of net oil-bearing sand in the Leek; the well tested up to 1,330 bopd of 25 degree API crude. The well was suspended such that the well can be used as for production further to appropriate completion.

A second appraisal well, 14/18b-16, was drilled in September 2007. The well was directionally drilled into Lower Cretaceous Leek sandstones to a depth of approximately 11,200 feet (9,640 feet true vertical depth) and tested 28 degree API sweet oil at a peak rate of 1,375 barrels of oil per day. The well penetrated 426 feet of gross oil-bearing sandstones in the Leek formation and a net pay interval of 115 feet (92 feet vertical). No water was produced during the test period and H2S levels were negligible. The well was suspended for future use as a producer.

In March, 2008, Ithaca drilled a third appraisal well, 14/18-17, to a depth of 9,046 feet true vertical depth, targeting possible upside and mapped as a southern extension to the oil pool. The well penetrated the Lower Cretaceous Leek sands at 8,842 feet, 413 feet above the Athena oil water contact.  Although oil bearing, the reservoir was of poor quality; the well has been suspended pending further evaluation of the development of the field and is likely to be sidetracked as a water injector. 

In June 2008, Ithaca drilled an appraisal/development well in the central part of the Athena accumulation, namely 14/18b-18. The well penetrated 447 feet of gross oil-bearing sandstones in the Leek formation and a net pay interval of 129 feet, on a vertical basis.  Following perforation of a 190 foot (178 feet vertical) interval, the 14/18b-18 well flowed at a stable rate of 2,330 bopd through a 52/64" choke and a stable rate of 1,150 bopd through a 24/64" choke over a 22 hours test period.  No water was produced during the test period and no H2S was detected. The well was suspended for future use as a development production well. All wells have been drilled from a central location to facilitate subsea development.

The likely development of the Athena oil pool consists of five producing wells and one water injector tied back to an FPSO via subsea manifold at the current drill centre location.  The FPSO will be tanker offloaded and provide all services and controls for the field.  The gross anticipated initial rate from the field will be approximately 22,000 barrels of oil per day under the current development scenario.

The development of Athena is being re-evaluated in the context of lower oil price, falling engineering costs and willing contractors who are keen to keep up activity levels.

The three main areas of Capital expenditure on Athena are drilling, subsea equipment and FPSO conversion. Ithaca is seeking collaborative contractual arrangements with key contractors to allow a minimum of advance Capital expenditure, with rewards paid out of field revenues after first oil. This may include 'bareboat' drilling rates with completion bonuses, sale and leaseback of subsea facilities and residual value credit for the FPSO contract.

The previously defined development scheme was re-examined in the light of rising oil prices during 2009. This work concluded with the decision to push forward with developments. Prior to the launch of the Athena Project in February 2010 extensive engineering studies were undertaken to progress the FPSO layout design plans and capture failing costs for developments. Revisions to the existing Environmental Assessment and Field Development Plans have been made with resubmission occuring H1 2010 with acceptance possible in early H2 2010. Acceptance of these changes will trigger probable commitment to the full FPSO, Drilling and Subsea development contracts in mid 2010. It is likely that drilling and installation work will take place and be completed early 2011 to allow first oil in mid 2011 with follow on drilling potential to occur into 2012.

Athena has potential for increased reserves. The envelope of the reservoir sand could be much greater than that to which reserves have been ascribed and, as a stratigraphic pool, only future drilling will disclose the effective extent of the porous reservoir.

The Athena field is located on a structural high point between the Jura and West Scapa Basins, which developed during Mesozoic rifting. The Leek and Scapa sandstones of the lower Valhall Formation were sourced from the Halibut Shelf to the south of the Athena field. Turbidite sands entered the basin at the junction through a transfer or fault zone between the NW/SE trending Jura Basin margin of the Halibut Shelf, and the SW/NE trending margin towards the West Scapa Basin. An area of low structural relief on the underlying BCU surface can be seen on the seismic interpretation. The sands were locally sourced from reworked Devonian alluvial clastic sediments that form the basement of the Halibut Shelf, possibly being eroded by fluvial systems on the exposed Halibut Horst, and stored in a shallow shelf environment. Turbidite sand lobes were deposited into the basin environment, initially directed to accommodation space created in the Jura Basin, but eventually filling to the east and onlapping onto the basin margin towards the north. The Leek and Scapa Sandstones pinch out into the calcareous Valhall Marls, forming the stratigraphic trap for the Athena Field to the north. To the south, the Leek and Scapa Sandstones either onlap or are truncated against fault scarp conglomerates derived from the Halibut Shelf edge.

Deposition of conglomerate / breccia facies along the edge of the Halibut Shelf is recognised in the area, with several exploration wells encountering tight conglomerates (e.g 14/18a-8, 8z) between Athena and the Scapa Field to the east. No conglomerates have been encountered in the main Athena field area, but are interpreted to have been encountered in well 14/18b-17z. The location and nature of the boundary between the fault scarp conglomerates encountered in 14/18b-17z and the Leek Sandstone of the main field area is currently not known.

The level of cementation appears to increase towards the north of the field, and towards the edges of individual sand lobes where they become thinner (seen when comparing 14/18b-15a with 14/18b-12). This suggests that with increasing distance from the clastic source area, with lower depositional rates, predominantly carbonate deposition of the Valhall Formation background takes over.

The main uncertainty on reservoir distribution is Net to Gross (NTG) away from well control in the core area. NTG, and reservoir thickness, decrease towards the north onto the structure, and this appears well constrained by the current wells in the core area. Uncertainty remains as to where the northern edge of the effective reservoir is (between 14/18b-18 and 14/18b-12). However, although 14/18b-18 encountered a relatively low NTG section, compared with 14/18b-15a, the reservoir properties (particularly permeability) appear significantly better. This suggests that there is not a strong link between NTG and well productivity. Uncertainty also remains on the location of the edge of the effective reservoir between 14/18b-15a and 14/18b-17z. The location of conglomerates along the Halibut Shelf edge is a recognised regional trend.