Rising onshore drilling
costs making deepwater
Rising US onshore drilling costs are making
deepwater E&P more competitive, according
to a recent report from Westwood Energy.
Data from the Westwood’s Energent team
in Houston indicates that consumption of sand
for hydraulic fracturing in the onshore US
market hit new highs of over 30 billion lbs
( 13. 6 billion kg) in 2Q 2017, topping the previous peak in 2014, despite only half the number
of land rigs working. The US completions mar-
ket is running in overdrive, the report said.
Onshore US contractors are scrambling
to reactivate pressure pumping equipment,
assemble crews, and open new sand mines
in order to keep up with demand. Insights
from Westwood’s Energent team suggest that
the market is expecting “double-digit” price
increases in 2018. This is expected to average
circa 15%. But in some segments, such as
proppant, reported price inflation is currently
significantly higher than this.
Offshore, the market is also recovering.
However, pricing pressure is absent. The industry simply built up too much capacity for the
expected level of activity, leading to an oversup-
ply of rigs, construction vessels, and support
vessels. This is good news for E&P companies
that can now take advantage of lower pricing
when sanctioning new developments.
Activity levels are certainly showing encour-
aging trends, Westwood said. A total of 17 FPS
units were ordered in 2017 (compared with
zero orders in 2016), and a further 19 units
are expected to be ordered this year.
E&P companies are starting to report that
some deepwater projects have more favorable
project economics than shale. One example
was cited by Hess Corp. in recent weeks,
which indicated that the Liza Phase 1 project
in Guyana required circa $35/bbl in order to
break even, while a comparable onshore project in the Delaware basin required $45/bbl to
break even. Guyana has proven to be a huge
success for ExxonMobil and its partners, with
total recoverable resources now estimated at
over 3. 2 Bboe. A second FPSO for Liza, with
a production capacity of up to 200 kbbl/d, is
expected to be ordered in 2019.
Looking forward, Westwood is tracking
39 FPS units currently under construction,
and has identified nearly 100 further FPS
deployment prospects in the coming years.
The firm said that this data was a source of
“cautious optimism” for the offshore sector
in 2018, and an opportune moment for E&P
companies to be sanctioning projects.
2018 drilling goals
Lundin Nor way expects to spend $115 mil-
lion this year on exploration drilling in the
The line-up includes four wells (as partner)
in the southern Barents Sea. One will be on
the Svanefjell prospect in license PL659; an-
other on Shenzhou in PL722; and two in the
southeastern Barents area on permits award-
ed under Norway’s 23rd licensing round.
One of these wells will target the deeper ho-
rizons of the Korpfjell prospect in PL859, and
the other the shallow horizons of Gjøkåsen
Elsewhere, Lundin plans to participate in
drilling of the Lille Prinsen prospect in PL167
in the Utsira High region of the North Sea;
on Frosk in PL340 in the Alvheim area (cur-
rently drilling); on Rungne in PL825; and on
the Mandal High prospect in PL860.
The company’s $135-million appraisal drilling
line-up is as follows: two operated wells in the
Utsira High area, comprising one on the Luno II
discovery, where a success would lead to devel-
opment planning; and one horizontal appraisal
well and testing at Rolvsnes, which could de-risk
the potential in the larger basement high area.
Both structures Luno II and Rolvsnes are
potential subsea tiebacks to the company’s
Edvard Grieg production complex.
In addition, Lundin will commission an ex-
tended test of the Alta oil discovery in the
southern Barents Sea, which involves drilling
a horizontal production well and producing to
a tanker for up to two months, the aims being
to reduce uncertainty around the recovery
mechanism and provide the basis for develop-
The 2018 appraisal budget also includes
expenditure on front-end engineering design
and PDO studies for Johan Sverdrup Phase 2
in the North Sea.
First-phase SNE oil
project offshore Senegal
to target 240 MMbbl
Cairn Energy says the partners in the deep-
water SNE oil field offshore Senegal are close
to concluding appraisal and concept select
definition for a first-phase development.
They hope to have secured government
approval for their exploitation plan by the
end of this year and are targeting first oil in
2021-2023. The plan will cover development
of the entire SNE resource base, estimated
at 563 MMbbl of oil.
Under the first phase, the partners expect
to drill up to 25 wells, targeting around 240
MMbbl, mainly from the S500 lower reser-
voir with an initial target plateau range of
Elsewhere, Cairn expects exploration drill-
ing to start next year on its two licenses in the
Sureste basin offshore Mexico. Both were
awarded last year – one is operated, the other
Across the waters of northwest Europe,
the company expects to participate in up to
10 exploratory wells this year, targeting up to
1. 5 Bboe from a variety of play types, includ-
ing the Barents Sea. Operator Wintershall
should submit its development plans for the
Nova (ex-Skarfjell) field in the northeast of
the Norwegian North Sea before mid-year.
Cairn, which has a 20%, anticipates first
oil in 2021 and plateau production later on
of 50,000 b/d.
Development calls for two subsea templates
tied back to the ENGIE-operated Gjøa plat-
form for processing and export. Gjøa will also
provide lift gas to the field and water injection
for pressure support. •
Aker BP has the approval of
Norway’s Petroleum Safety
Authority for a drilling pro-
gram at the Ivar Aasen field
in the North Sea. This covers
use of the jackup Maersk
Interceptor for drilling and
completion of two water injec-
tion wells (16/1-D- 6 and 16/1-
D- 7). Drilling should get under
way this month. (Courtesy