the Northland-Reinga basin (17NRN-R1).
• One 64,978-sq-km area surrounding existing permits in
the Taranaki basin (17TAR-R1).
• One 49,630-sq-km area in the Pegasus-East Coast basin
off the east of the north island (17PEC-R1).
• One 5,569-sq-km enclave in the Hawk Bay region in the
East Coast basin (17PEC-R2).
• One 204,928-sq-km region surrounding existing permits
in the Great South-Canterbury basin off the southeast of the
south island (17GSC-R1).
The onshore blocks are:
• One 1,021-sq-km area in the Plymouth region of the Ta-
ranaki basin (17TAR-R2).
• One 3,568-sq-km block in the Great South basin at the
southern tip of the south island (17SLD0-R1).
The combination onshore and offshore area covering 1,475
sq km is in the north Taranaki basin (17TAR-R3).
The blocks are being offered on a work program bid process.
The offer is open until Sept. 6. The government expects to grant
the successful tender offers in December.
Eni discovers oil with first Mexico well
Eni SPA discovered the presence of oil in the Amoca- 2 well,
the first drilled by an international operator in Mexico since
the 2013 energy reform. The well lies in the Gulf of Mexico’s
Southeast basin 1,200 km west of Ciudad del Carmen in 25
m of water in Mexico’s Campeche Bay. Eni was awarded the
67-sq-km block along with Amoca, Mizton, and Tecoalli fields
in Mexico’s National Hydrocarbons Commission Round One
second tender in 2015 (OGJ Online, Sept. 30, 2015).
Amoca- 2 reached a total depth of 3,500 m and encountered
110 m of net oil pay from several Pliocene reservoir sandstones,
of which 65 m were in a deeper, previously undrilled horizon.
Shallower formations contained 18° gravity oil. Eni said the
newly discovered deeper sandstones “contain high quality light
oil.” The operator is assessing reserves.
The company will move ahead with its Area 1 drilling campaign with a new well in the Amoca area, Amoca- 3, followed
by the Mizton- 2 and Tecoalli- 2 delineation wells, which will
be drilled this year to appraise existing discoveries as well as
targeting new undrilled pools.
Eni holds a 100% stake in the Area 1 production-sharing
agreement and is evaluating options for a fast-track phased development of the fields.
Cairn Energy group finds more oil offshore Senegal
A joint venture led by Cairn Energy PLC made an oil discovery
in its VR- 1 well offshore Senegal, notching up its eighth consecutive successful well in the region since drilling began in 2004.
Consortium member FAR Ltd., Perth, announced that the VR- 1
well intersected a 97-m gross oil column across multiple reservoirs
and recorded the highest net pay in any well drilled there to date.
Wireline logging and sampling through the SNE section of
the well have been completed. VR- 1 will now be deepened into
the secondary Aprian carbonate objectives below SNE field.
VR- 1 was drilled 5 km west of the SNE- 1 discovery well and
is being drilled to appraise the lower and upper reservoir units
in the western sector of SNE field (OGJ Online, Mar. 8, 2017).
FAR said the Lower 520 reservoir, which is a key reservoir in
plans for the Phase 1 development of SNE field, showed the best
reservoir properties of all other reservoirs sampled in the field
to date. VR- 1 intersected a 16-m oil interval in this reservoir.
The deeper 540 reservoir, with an 11-m interval in oil, has
only been seen previously in the SNE- 2 well where the oil in-
terval was just 2 m thick.
FAR anticipates that the results of the VR- 1 well so far, to-
gether with the recent SNE- 5 well results, will lead to a revision
of contingent resources estimate for SNE field as well as impact
the design of the development plan.
The 1C resource is currently estimated at 348 million bbl vs.
the minimum economic field size of 200 million bbl.
FAR has 15% interest in SNE field. Cairn, ConocoPhillips,
and Petrosen hold respective interests of 40%, 35%, and 10%.
Statoil submits development plans for Njord, Bauge
Statoil ASA has submitted plans for development and operation to the Norwegian Petroleum Directorate for Njord field and
the nearby Bauge discovery, with total capital spending of 19. 8
billion kroner. Production is expected to start in both areas in
fourth-quarter 2020.
Njord, which began producing in 1997, was shut down in
2016 and the Njord A platform and Njord B storage ship were
towed to shore for repairs and upgrades.
Operator Statoil and partners in the Njord Unit in production licenses 107 and 132 expect to spend 15. 7 billion kroner
on Njord. Investments include reinforcement of the hull of the
Njord A platform, upgrade of deck equipment, the drilling of
10 production wells, and upgrades on the Njord B storage ship.
NPD said estimated remaining reserves at Njord are 6. 2 million cu m of oil, 16. 3 billion cu m of natural gas, and 4. 1 million
tonnes of natural gas liquids.
Bauge, 16 km northeast of Njord, will have expected investments of 4. 1 billion kroner. Plans include the drilling of two
production wells and one injection well, a pipeline to Njord A,
and an umbilical from the subsea Hyme field.
NPD said Bauge was proved in 2013 with the 6407/8-6 well.
Recoverable resources are estimated at 7. 9 million cu m of oil,
1. 9 billion cu m of gas, and 1 million tonnes of NGLs.
Statoil said Bauge will be the first user of Cap-X technology,
a next-generation subsea production system. “Cap-X costs less
to produce and install,” said Margareth Ovrum, Statoil’s executive vice-president for technology, projects, and drilling.
DRILLING & PRODUCTION QUICK TAKES
Maersk Oil to redevelop Danish North Sea’s Tyra field
Maersk Oil has reached an agreement with the Danish government providing terms to enable the Danish Underground Con-
