The current operational status, the findings of our preliminary technical evaluation and the planned program to bring Longtom to a full field development decision are summarized in this release.
• The results of the Longtom-3 well to date indicate that a commercial gas
volume exists which can underpin a field development
Since the last report the 7" production liner has been successfully run and cemented inside the horizontal section, across the 3 deepest sand bodies (the 100, 200 & 300 sands) of the Admiral formation.
The well bore has been circulated to brine, and 1069 meters of perforations have been shot in the production liner.
Future operations will include the perforation of an additional 60 meters of gas bearing sand in the 400 reservoir, the running of the production completion string and the sub-sea (production) christmas tree on the wellhead prior to testing of the well.
Two production tests will be undertaken at Longtom-3, firstly the 400 reservoir sands (test #1) and then the 100-300 reservoir sands (test #2). The 400 reservoir sands were not successfully tested in Longtom-2, which Nexus believes was due to a downhole valve malfunction.
It should be noted that the drilling rig is equipped with a testing package that has a maximum flow rate capacity of 30 MMscf per day. This is the rate limit of a single flare boom.
The Longtom-3 well is being completed in 4 of the 5 gas bearing sands that have been encountered in the Longtom field to date. From deepest to shallowest, these are named the 100, 200, 300 and 400 reservoir units. Longtom-3 is not being completed in the shallowest, minor "500" sand, which will likely be completed in either one or both of the two planned future Longtom wells.
Analysis of the Longtom – 3 well results to date clearly demonstrate that:
1. Seismic amplitudes coincide with gas filled sand bodies, as was predicted by Nexus predrill seismic data analysis. Future Longtom wells will target gas bearing reservoir sands identified on seismic which cannot be efficiently drained by Longtom-3.
2. Seismic amplitudes indicate where a minimum thickness of gas filled sand exists, providing a high degree of confidence in the predicted gas volumes.
3. The sands in the Longtom field are stratigraphically connected between the wells (and hence are not stratigraphically isolated sand bodies, which was Nexus' downside resource scenario). The Longtom reservoirs appear to be connected to a series of vertically separate, but laterally connected common aquifers.
4. State of the art measurement and analysis that was deployed throughout the drilling of both in the Longtom-3 pilot hole and in the main horizontal wellbore indicating at least 520 meters of sand have been intersected with an interpreted permeability greater than 1 mD (milliDarcies). In excess of 830 meters of reservoir has been intersected with porosity greater than 10% (more than 80% of the gross reservoir).
5. The Longtom field reservoirs are a channel sand system where reservoir quality will vary across the field. Numerical reservoir simulation indicates that regions of higher permeability rock will act as a conduit to drain less permeable reservoir regions and that almost all gas bearing reservoir rock will contribute to Longtom reserves during the life of the field.
Providing the Longtom #3 well flows at commercially sustainable rates during testing, the company expects to be in a position to book reserves for the Longtom field in October/November 2006. The decision to complete the well as a production well has been based on the fact that the company is highly confident that reserves will exceed the economic limit; a contract exists for the sale of 350 PJ's of Longtom Gas; and that front engineering and design (FEED) for the Longtom field development has recently been completed.
To determine the revised gas volumes for the field, Nexus will map and then simulate the depletion characteristics for each individual reservoir unit in order to confirm the optimal well development plan. This is still expected to involve 3 wells (including Longtom-3); one more before first production and one approximately 3-5 years after first gas.
Upon conclusion of Nexus' reserves estimation, an Independent Auditors report will be commissioned, after which Longtom gas and condensate reserves will be formally booked.
Nexus will provide all relevant Longtom-3 information to Apache according to the terms of its joint venture agreement in order for Apache to decide whether or not to make a back-in election to the Longtom project.
Apache has twenty one days after the provision of all data by Nexus to either make its backing election or otherwise concede its interest in the graticular block containing Longtom to Nexus. The terms of the Apache buy-back right are the repayment of its proportional share (62.5%) of appraisal costs, plus a penalty multiple of six times this share.
As part of the gas sales agreement between Nexus and Santos, Santos has an option (providing Apache does not elect to back-in) to purchase an interest of up to 35% in the field for A$ 2 million per percentage point in the Longtom reservoirs encountered to date. Santos have a period of one month from granting of the production License in which to exercise this option.
As part of the agreement between Nexus and Santos, Nexus will submit a Preliminary Field Development Plan (FDP) to Government prior to the end of 2006. The FDP will detail Nexus' plans for Longtom gas field development, and is the first formal step toward obtaining a Production License for the field.
Subject to a successful flow test over the coming two weeks, Nexus is confident that Longtom will proceed to full field development. Nexus believes that the Longtom – 3 well has helped to define a substantial reserves base and a full field development decision is likely to be made by late 2006. It is expected reserves base will continue to be further enhanced by the drilling of a second Longtom development well planned for late 2007.
The Longtom-3 well is located in VIC/P54, in the offshore Gippsland Basin, Victoria.
Nexus Energy is the operator of VICP54 and holds a 100% stake. The Longtom -3 well is a sole risk appraisal project located in the VIC/P54 exploration permit. The sole risk appraisal project is being operated and funded by Nexus Energy. Apache Northwest Pty Ltd has back in rights pursuant to a joint venture agreement which enables Apache Northwest Pty to participate in any potential Longtom development upon the payment of a back in penalty.
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