Statoil seeking recovery
boost on Åsgard, Snorre
The crane barge Saipem 7000 has installed the frst components for the subsea
compression station serving Statoil’s Åsgard complex in the Norwegian Sea. These
comprised the 1,800-metric ton ( 1,984-ton)
subsea template that will contain the compressors and the module providing power
for the new subsea system, to be installed on
the Åsgard A production ship 43 km ( 27 mi)
away. Water depth at the site is 300 m (984
ft). The 22 modules forming the compressor
trains will be installed next year.
Assuming Statoil achieves its goal of verifying the compressor technology, the facility
should be ready to start operating on Åsgard
in 2015. Over time, the company expects the
$2.9-billion project, which will compress up
to 21 MMcm/d of gas, to increase recovery
from the Midgard and Mikkel reservoirs
within the Åsgard area by 280 MMboe.
Saipem 7000 has installed the first Åsgard subsea
template. (Photo courtesy Øyvind Hagen, Statoil)
In the North Sea, the company has commissioned what it claims is the world’s frst
well stimulation tanker, designed to boost
oil extraction from the producing Snorre
feld. Siri Knutsen, a former shuttle tanker,
was converted for the role and now features
a new mezzanine deck housing three fresh
water modules, fve pumps, a control system, and a larger accommodation area.
Fresh water and sodium silicate will be injected into Snorre’s E-4H water injector well
as a test case to increase oil output from the
P- 15 production well. Previously on Snorre,
Statoil has pumped water into the porous
sandstone rock to press out oil; however,
sandstone quality varies in different parts
of the reservoir, leaving large volumes unswept. Sodium silicate is affected by the
reservoir temperature, taking on a gel-like
consistency that blocks the pores in the reservoir where water fows most easily, forcing the water to fnd new routes.
With the new injector well, hydrochloric
acid will be added to the water mix to adjust the PH level. The company, which has
been working on the new technique since
2008, says the planned pilot wells are in a
relatively isolated segment of the reservoir.
Halliburton and Knutsen are supplying the
equipment and the vessel, at a total estimated cost of $62.5 million.
Developments off Iceland
The Faroese government has awarded
Danish company DONG Energy two licenses covering six offshore blocks in the
Faroe-Shetland basin, under the islands’
Open Door license round. DONG’s blocks
extend over 900 sq km (347 sq mi), and are
west of the developed Foinaven and Schiehallion felds, and the undeveloped Tornado. They also include Marjun, the sole
publicized Faroese offshore oil discovery to
date. DONG plans to apply new 3D seismic
data and in-house processing techniques to
progress prospects.
To the north, Iceland’s National Energy
Authority Orkustofnun is reviewing local
company Eykon Energy’s application for the
country’s second licensing round in the offshore Dreki area. The company submitted
its original bid last year, on the understanding that it would need to bring in a bigger
partner to manage its planned exploration
program. In June China’s CNOOC stepped
into the breach – Orksustofnun is now reviewing the partnership’s fnancial and technical capacity to carry out the work, and will
make its decision on awarding the license
this fall. Norway has the right to back into
25% of any concession Iceland awards in this
offshore region, which is between the two
countries.
Breagh re-think
First gas was due to fow this month from
Breagh, one of the larger feld developments in the UK southern North Sea in recent years. Operator RWE Dea and partner
Sterling Resources are now turning their attention to Breagh Phase 2, focused on the
eastern side of the feld.
The project has been running behind
schedule due to a combination of weather
delays and commissioning issues at the terminal in Teesside, northeast England, that
will receive the feld’s gas. As a result, according to feld analysts BritBoss, capex is
far beyond the $649 million budgeted. On
the plus side, the performance of the frst
three production wells drilled suggests
reserves may be higher than previously
thought, causing the partners to revise their
Phase 2 plan.
Sterling said well A03 appeared to penetrate a Carboniferous section with better
porosity and higher permeability. The same
applied to the subsequent A05 well – once
drilling here is completed, the geological
Jeremy Beckman • London
model for the north/northeastern parts of
the 80-sq km (31-sq mi) feld will be refned
and the new well data will be used for Phase
2 adjustments.
Phase 1 is based around an unmanned 5,400-
ton platform on the western part of the feld
built by Heerema Vlissingen in the Netherlands. The gas will be exported to Teesside via
a 100-km (62-mi), 20-in. subsea pipeline with a
9-km ( 5.6-mi) onshore section.
In the UK central North Sea, Antrim Energy
is making a fresh attempt to develop the small
heavy-oil Fyne feld, discovered by Mobil in
1986. Antrim had planned to use Teekay’s circular Sevan FPSO Hummingbird Spirit as the
central production system, with three subsea
drill centers. But a poor result from the East
Fyne appraisal well last year caused partners
Premier and First Oil to exit the license.
Now Enegi Oil and partner Advanced Buoy
Technology (ABT) have agreed to perform
fresh engineering studies based around ABT’s
marginal feld production buoy concept with
oil offoaded to a tanker. If they can make the
economics work – and Britain’s government
approves their entry into the license on a 50-
50 basis with Antrim – this could be the North
Sea’s frst unmanned buoy development, although Energi/ABT have other application
options elsewhere in the UK sector.
UK attractions
remain strong
Wood Mackenzie forecasts £ 44 billion
($66.5 billion) of development capex across
the UK continental shelf over the next fve
years. The analysts, marking 40 years of reporting on the sector, add that currently 126
companies hold interests licenses offshore
the UK. Although this is way below the 292
present in the sector in 1973, it is still the
highest total in any European country.
Another big change since those early days
of UK North Sea production is that today,
more than 60% of the sector’s commercial
value and three-quarters of operatorships
are held by companies that are not majors.
And following CNOOC and Sinopec’s deals
with Nexen and Talisman last year, Chinese
companies will produce around 10% of UK
liquids during 2013-2017, the analysts claim.
Since the frst UK offshore felds were developed, nearly £300 billion ($453.5 billion)
in 2013 terms has been invested in upstream
development, they add. During 2012 UKCS
development spending reached £ 11 billion
($17 billion), similar to levels in real terms
last seen in the mid-1970s. Although this can
partly be attributed to cost infation and the
higher costs needed to develop more challenging reserves, it suggests that the sector
remains vibrant. And despite its maturity,
the country still ranks as a Top 10 destination for investment globally. •
