Nexen's third quarter production volumes averaged 249,000 boe/d (209,000 boe/d after royalties). Buzzard continues to perform well and contributed 89,600 boe/d (207,500 boe/d gross) to our quarterly volumes. Gulf of Mexico production was negatively impacted by hurricanes Gustav and Ike. While we incurred only minor damage from Gustav, Ike caused significant damage to a number of our properties, but more importantly, to surrounding infrastructure.
Most of our deepwater production is currently shut-in awaiting facility or downstream pipeline repairs. Gunnison received minor damage while at Aspen and Wrigley, third-party host facilities were damaged. These fields are expected to resume production this year but timing is uncertain because of reliance on third-party repairs. Our Green Canyon 6, 50 and 137 fields are shut-in following the destruction of a third-party processing platform. We are currently evaluating alternative production options for these fields.
On the shelf, Vermilion 321/340 incurred substantial damage to the lower decks on some of the platforms. We do not expect production there to be restored until 2009. A number of our other shelf properties have been brought back online and we are currently producing 6,500 boe/d compared to 30,000 boe/d prior to the storms. For the fourth quarter, we expect our Gulf of Mexico production to average between 10,000 and 20,000 boe/d. Volumes will depend on the timing of repair work and the readiness of third-party infrastructure, such as production platforms and pipelines. We carry insurance coverage for physical damage caused by hurricanes, subject to certain deductibles.
Syncrude volumes were strong during the quarter as a result of improved uptime. In the second quarter, production was down as a result of maintenance to a sulphur unit that took longer than expected. In early September, turnaround work commenced on one of Syncrude's cokers. This turnaround was completed on schedule in mid October but following the start-up of the coker, unexpected vibrations were experienced on a fuel gas compressor. Unplanned compressor repair work has delayed the coker restart until early November, after which we expect production volumes to return to 25,000 bbls/d, net to us.
Long Lake-Bitumen Production Ramping Up
Commissioning of the gasifier was delayed by about three weeks. Upon initial test firing, mechanical issues were identified with several automated valves and the burners required change-out. The burner change-out work has been completed and the automated valves have been repaired. The valves have been reinstalled and the gasifier is in the process of being refired. Once the gasifier achieves steady state operations, the hydrocracker and sulphur units will be started and we expect first synthetic production to commence shortly thereafter.
On the bitumen front, the reservoir is performing well, the reliability of our surface facilities is improving, steam injection rates are at their highest levels since SAGD start-up and production rates are increasing. In the field, 45 of the total 81 well pairs have now been converted to SAGD operation, gross production rates averaged 15,200 bbls/d for the first half of October and recently exceeded 19,000 bbls/d. The average steam to oil ratio (SOR) for the wells that have been converted to SAGD operation is currently about 4.0. About one-quarter of these wells are already at or below our long-term SOR expectation of 3.0 and approximately 10% have achieved targeted bitumen production rates. We expect to reach full design rates of 72,000 bbls/d of bitumen production (36,000 bbls/d net to us), upgraded to approximately 60,000 bbls/d of Premium Sweet Crude (PSC(TM)) late next year or early 2010.
"After years of construction at Long Lake, we are pleased to be very close to first production of synthetic crude. Commissioning and start-up of the upgrader is a complex and rigorous process and these activities will be carried out with full attention to safety and the environment," stated Fischer. "We expect Long Lake to generate significant value for our shareholders as the patented process substantially reduces the need to purchase natural gas, a key cost driver in oilsands projects."
Phase 1 of Long Lake will develop approximately 10% of our oil sands inventory. We are engaged in engineering and planning for Phase 2 and have received regulatory approval for the Phase 2 upgrader. Ultimately, the sanctioning of Phase 2 will depend on multiple factors including the initial performance of Phase 1, receiving regulatory approval for Phase 2 SAGD operations, receiving clarity on proposed climate change regulations, finalizing cost estimates and an improved economic environment.
"We are committed to the development of our oil sands leases in a measured and responsible manner," commented Fischer. "However, given continuing cost pressures in the industry, uncertain financial markets and lower commodity prices, we believe it is best to be patient in the near term."
North Sea Continues Successful Exploration Program
In the North Sea, we drilled a discovery at Pink that encountered 57 feet of net oil pay. This discovery was followed up with a sidetrack delineation well that encountered 134 feet of net oil pay. These results are encouraging and consistent with pre-drill estimates. We see additional prospects in the area and are currently assessing them. Pink is a candidate for co-development with Golden Eagle where we are currently reviewing development options. We have a 34% operated interest in Golden Eagle and a 46% operated working interest in Pink.
During the quarter, we also made a discovery at Blackbird which is located six kilometres south of our operated Ettrick field. The well encountered 111 feet of net pay in multiple zones, was drill-stem tested and flowed at an average restricted rate of 3,800 bbls/d. Further appraisal is planned with a view to tieing Blackbird back to Ettrick. We operate both Ettrick and Blackbird and have an 80% working interest in each.
Delivery of the floating production, storage and offloading vessel (FPSO) we are leasing for Ettrick has been delayed until December following commissioning delays in Singapore. The cost of these delays is borne by the owner of the FPSO. First production is now scheduled for early 2009. Production volumes are expected to average between approximately 15,000 and 20,000 boe/d in 2009. The FPSO is designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas and has capacity for nearby discoveries such as Blackbird.
Gulf of Mexico-Encouraging Hydrocarbon Shows at Cote de Mer
At our Cote de Mer prospect, located on the Louisiana coast, exploration drilling was interrupted by hurricanes Gustav and Ike. Upon resuming drilling operations, we experienced drilling difficulties. We have encountered the target reservoir but have not yet reached the target depth of 21,900 feet. We are encouraged by the preliminary data obtained and are currently conducting pipe recovery operations in order to resume drilling to reach target depth. We have a 37.5% working interest in this prospect.
In the Eastern Gulf of Mexico, we drilled the Fredericksburg exploration well. Target sands were reached but we did not encounter commercial hydrocarbons. This was the third prospect to be drilled in the area following earlier successes at Vicksburg and Shiloh. We remain optimistic about the potential of this emerging play and are currently working with Shell, the operator, to finalize 2009 plans for this area. We expect to drill an additional well here next year and have a feasibility study underway to assess development options for Vicksburg. We have a 25% interest in Vicksburg and a 20% interest in Shiloh and Fredericksburg.
Development of the Longhorn discovery continues and first production is expected mid-year 2009 with a peak production rate of approximately 200 mmcf/d gross (50 mmcf/d, net to us). We have a 25% non-operated working interest here and ENI is the operator.
At Knotty Head, we plan to drill an appraisal well in 2009 when the first of our two new deep-water drilling rigs arrives. We have a 25% operated interest in the field.
Shale Gas Drilling Program Continues
Following the success of last winter's drilling program in the Horn River basin in northeast British Columbia, we decided to drill two horizontal wells this summer. The wells have been drilled and are being fraced. The results from these wells will be taken into consideration as we plan our upcoming winter program for the area.
This shale gas play has the potential to become one of the most significant shale gas plays in North America. It has been compared to the Barnett Shale in Texas by other operators in the area as it displays similar rock properties and play characteristics. We have approximately 88,000 acres in the Dilly Creek area of the Horn River basin with a 100% working interest. As previously announced, we estimate these lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource which could double our total proved reserves. Further appraisal activity is required before these estimates can be finalized and commerciality established.
"Shale gas is a great addition to our portfolio of assets," said Fischer. "The potential resource size is significant and its short cycle-time development complements our longer cycle-time projects by providing visible near-term growth."
Offshore West Africa, the Usan Development Progresses
Development of the Usan field, offshore Nigeria is fully underway. The field development plan includes an FPSO vessel with a storage capacity of two million barrels of oil. All major contracts for deep-water facilities are proceeding with detailed engineering and early procurement of equipment and materials. The Usan field is expected to come on stream in early 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d net to us).
The Usan field development is located in OML 138 and is covered by the original production sharing contract for OPL 222 issued in 1993, with the Nigerian National Petroleum Corporation as concessionaire. The contract conveys the right to develop and produce crude oil and continue with exploration activity. We are currently processing three-dimensional seismic in anticipation of further exploratory drilling in the area in 2009. The Usan field was discovered in 2002 and is located approximately 100 km offshore in water depths ranging from 750 to 850 meters. Drilling of the development wells is expected to commence next year. Nexen has a 20% interest in exploration and development along with Elf Petroleum Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%).
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