The test of the lower sands of the Admiral Formation ("100, 200 & 300 sands") flowed at an estimated rate of 77 MMscf/d through a 1 1/4" choke directly to the flare. The maximum flow rate using the test separator was 59 MMscf/d through a 60/64""inch choke with a flowing well head pressure of 2946 psi. Flow rates through the separator were limited by the capacity of the testing equipment.
The well was opened up at 5 PM on Friday September 15th and flowed for 24 hours before being shut in to monitor the pressure response from the reservoir.
An average condensate rate of 324 barrels per day was recorded during a flow period with a gas rate of 36 MMscf/d. The condensate ratios recorded from this test are approximately twice that recorded in the Longtom -2 test over the 200 sands, and 5 times those recorded in the Longtom-3, test #1 over the 400 sands. This indicates that the laterally extensive 100 sand is more condensate rich than predicted. The additional condensate will be an economic benefit to the Longtom project. Sampling during the test recorded expected levels of carbon dioxide (less than 1%) and less than 1 part per million hydrogen sulphide.
The results from this test demonstrate the excellent flow capacity of the lower Longtom reservoirs with a horizontal well completion. The flow capacity of Longtom-3 alone is expected to be sufficient to supply the anticipated maximum contract rate requirements for the Longtom Field.
The 100, 200 and 300 sands are expected to hold approximately 80 % of field gas volumes and will provide the main source of commercial production. The shallower 400 sands tested earlier (Longtom -3, test 1) are at lower pressure and are expected to be drained later in field life.
Longtom -3 is expected to be the first of three production wells required for the field. One more Longtom well is planned prior to first commercial production. The testing of the Longtom-3 well through a production completion and Xmas tree means the well is now ready for commercial production without any further rig intervention being required.
Nexus Managing Director Ian Tchacos said "This is an exceptional result confirming our long held belief in the viability of the Longtom project. The successful deployment of a horizontal completion in the Longtom reservoirs is an innovative solution that has yielded commercial flow rates necessary to confidently proceed with field development"
The Company recently reported that the results obtained from the drilling of the Longtom-3 well confirmed the existence of commercial gas volumes. Nexus expects to be in a position to report revised volumes for the field which will be classified as reserves within the next three months.
Front engineering and design for the Longtom field development has recently been completed and the Company plans to submit a preliminary Field Development Plan to government prior to the end of 2006.
Nexus has a contract with Santos for the sale and processing of 350 Pjoules of Longtom gas over an anticipated 12 year period at the adjacent Santos owned and operated Patricia-Baleen gas plant.
The well is currently being suspended as a future producer. The Longtom-3 well is located in VIC/P54 offshore Australia in the Gippsland Basin.
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