1-Offshore Well Spudded in Liberia
ExxonMobil Exploration and Production Liberia Ltd. has begun drilling the deepwater Mesurado-1 exploration well, according to partner Canadian Overseas Petroleum Ltd. (COPL).
Using the Seadrill drillship West Saturn, the well is targeting oil in Late Cretacous sands. It is in about 2,500 m (8,202 ft) of water.
Mesurado-1, located about 50 mi (80 km) offshore on block LB-13, is said to be Exxon’s first well operated offshore Liberia. The company negotiated its entrance into the Liberia block in 2011 from COPL’s wholly-owned subsidiary, Canadian Overseas Petroleum (Bermuda) Ltd.
Block LB-13 comprises more than 625,000 acres (2,500 sq km), 18 mi (30 km) offshore Liberia in water depths ranging from 250 to 10,000 ft (75 to 3,000 m).
Canadian Overseas Petroleum (Bermuda) Ltd. holds a 17% interest in block LB-13.
2-ONGC Finds More Oil, Gas Offshore India
ONGC has drilled three new discoveries offshore western and eastern India.
Well B12C-2(B-12C-A), drilled in shallow water on the B-12 (Dahanu) prospect in the Western Offshore basin, tested gas at 229,297 cm/d from the Upper Oligocene Daman formation, and 383 b/d of condensate.
Another well, B157N-1(B-157N-A), in the shallow-water Bombay Offshore area of the same basin flowed 640 b/d of oil and 31,050 cm/d of gas from a clastic interval in the Panna formation.
The result has broadened the scope for future exploration in the area north of the B157 concession, ONGC said.
In the KG shallow water offshore KG-PG basin off Andhra Pradesh state, well GS-71-1(GS-71-AA) on the GS-15/23 PML block produced 7.8 MMcmoe of oil and gas through a 12/64-in. choke; oil and gas in the Vadaparu formation via a 16/64-in. choke; and condensate and gas from the Ravva formation through a 16/64-in. choke.
However, ONGC has yet to determine the commerciality of this find.
3-More Workovers Planned in New Zealand
The Maari field offshore New Zealand now has a total of 10 producers and one water injector in service, according to partner Cue Energy.
No further drilling is currently planned, with the priority being to maximize production by optimizing up-time and deliverability of the wells.
The sole naturally flowing well is MR6A, which is now exhibiting increased water cut and which accounts for a large portion of the field’s declining production rates.
All other nine producers rely on electric submersible pumps for continued production and operator OMV is optimizing use of these and topsides facilities to enhance production.
OMV is also adding additional perforations in producing wells to improve production, as was the case with MR8A, where action lifted output by 1,600 b/d.
A similar job in MR9 has added around 500 b/d incremental production. The MR2 well is currently undergoing a workover, with similar activity scheduled for MN1.
The only planned shutdown over the next year will be in December to repair the water injection line. Once this work is complete water injection will be reinitiated, providing pressure support to some of the producers and thereby increasing production and ultimate recovery.
Otherwise, Cue has withdrawn from its three remaining licenses offshore New Zealand.
4-Offshore Mexico Group Lines Up Block 7 Well
Premier and its partners have completed their technical evaluation of block 7 offshore Mexico, including the amplitude-supported Zama prospect.
The company expects to soon receive an option notice to increase its equity interest in the license to 25%, with the first well set to be drilled in mid-2017.
Offshore Brazil, Premier has secured an extension of the first-phase exploration period for two operated licenses to 10 July 2019. The extension will help the company draw up cost synergies with other operators in the Equatorial Margin which plan to begin drilling during the second half of 2018.
In the offshore North Falkland basin, front-end engineering and design continues on the Sea Lion project with technical definition of the project well advanced, and the current breakeven price estimate at $45/bbl.
Premier anticipates further reductions through market engagement.
Offshore Indonesia, the company is targeting a final investment decision in 1Q 2017 on the Bison, Iguana, and Gajah Puteri gas field developments, to support long-term gas contracts to Singapore and Indonesia.
Finally, production from the Premier-operated Chim Sáo field off Vietnam has improved following an intervention campaign that included reservoir stimulation of three oil wells and a water injector.
The company says it has identified upside at Chim Sáo and plans further intervention work and two infill wells during 2017 to help sustain production levels.
5-North Sea Ravenspurn Well to Test Deeper Gas Play
Premier will participate in an exploration well on the Ravenspurn Deep North gas prospect in the UK southern North Sea.
Operator Perenco plans to test the deep Carboniferous play underlying the Ravenspurn field.
Premier has a 50% operated interest in the undeveloped Tolmount discovery in the same sector. The company is working with contractors to reduce the project’s capex and is targeting a concept selection at the end of this year, to be followed by front-end engineering and design in 2017.
There could be further upside in the Tolmount East and Tolmount Far East structures, with combined prospective resources of 400 bcf.
In the UK central North Sea, the company now estimates capex for the Catcher project at $1.7 billion, 24% down on the originally sanctioned figure, partly due to sterling’s weakness against the dollar (55% of the remaining expenditure is denominated in sterling).
Final tie-ins for the subsea spools were completed earlier this month, concluding the planned 2016 subsea campaign. All that remains next year is tie-in of the wells once available from the drilling program, and to support commissioning operations once the FPSO has arrived from Singapore and has been installed.
Work continues to assess the possibility of reducing the overall well count without impacting production. Well delivery is ahead of prognosis in terms of reservoir quality and flow rates and the first well (VP2) on the Varadero template, completed earlier this month, flowed 8,000 boe/d on clean up.
At the Keppel yard in Singapore, 12 of the 13 topsides modules have been lifted onto the FPSO, with the final module lift expected later this month.
As for the Premier-operated Solan field west of Shetland, which came on-stream earlier this year, the second producer well (P2) entered service in mid-August. While initial production capacity from the field was good, output is currently constrained at 10-13,000 boe/d due to lower than anticipated water injection capability, linked to underperformance from P2.
Various options are under consideration to increase water injection into the reservoir, necessary to maintain voidage replacement and to sustain reservoir pressure at higher production levels.