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Oilfield Technology
August
2015
the oil and gas industry is in the bottom 3% for efficiency and
productivity.
It is also worth bearing in mind that many operators were
struggling to make a profit in the high oil price environment and
that the low oil price is not solely to blame for the recent industry
difficulties. Even at US$100/bbl, around an eighth of production on the
UKCS was loss-making. For years collaboration and standardisation
have been key calls from the industry to streamline projects and
cut costs, both of which have been fought against due to the highly
competitive nature of the industry.
The ramifications of high-costs and low efficiency is emphasised
by the fact that it cost £3.6 billion in capital expenditure to find
1.1 billion boe between 2004 and 2007, while between 2011 and
2013, it cost £17.7 billion to discover 1.2 billion boe equivalent – an
unsustainable rate of return.
Agrowinggovernment role
The UK government has begun to play its part with the establishment
of the Oil and Gas Authority (OGA) and the announcement of a 10% cut
in the supplementary charge, which has been calculated to transfer
roughly £13 billion from the government to operating companies.
The tax decrease will alsomake the UK fiscal regimemore attractive
in a global context as the UK’s percentage government take is now lower
than both the Gulf of Mexico and Brazil. However, more is still required
from the government to assist inmaking exploration and appraisal (E&A)
workmore economic as these recent tax cuts will have very little impact
on operator’s decisions to drill smaller prospects (under 50million bbls).
On average around one in three wells will be successful, but there
is no financial support from the government for unsuccessful wells, a
factor that discourages E&A activity. On the UKCS only 14 exploration
wells were drilled in 2014, compared to 44 in 2008. The UK also does
not compare favourably to Norway, where more than 40 exploration
wells were drilled in 2014.
The possible advantages to increased exploration can be seen
here, where the Johan Sverdrup field, discovered in 2010, is estimated
to hold around 2 billion bbls of oil. This is a good example of the
possible rewards of investing in exploration, even in a mature basin.
For an equivalent success to be realised on the UKCS however, there
needs to be a change in exploration strategy; the 10 year average success
rate for exploration wells is around 30%, but between 2012 and 2014 that
dropped to around 18%. Also, between 2012 and 2014, 86 exploration
wells were drilled, and only 166million boe discovered – less than
2million boe per well. Better pre-drill analysis and improved access to
data are likely to be necessary to better these figures, while a different
strategy in terms of drilling larger, riskier prospects may also be required.
UKsupplychainopportunities
While exploration in the UKCS is at a low, there remain plenty of
opportunities for the UK supply chain with several developments
moving forward. One of the more advanced of these is the US$7 billion
Mariner heavy oil field, located in Block 9/11a, operated by Statoil.
Several major contracts have been awarded on the project to
date, including the engineering, procurement and construction (EPC)
contracts for the steel jacket and topsides to Dragados Offshore and a
consortiumof Daewoo Shipbuilding and CB&I respectively. Subsea 7 has
also been awarded a contract on the Mariner project for the installation
of 39 kmof rigid flowline and the flexible riser system. Topside
construction began on the project last autumn and is expected to be
installed in 2016, while the jacket is complete and ready for load-out.
Subsea work is also currently underway, with the pipelay of the gas
import line taking place. The subsea manifolds have yet to be placed.
Much of the UK supply chain’s opportunity in the Mariner field may
present itself post-production. The field is expected to have a large
Opex due to the heavy (11 – 15˚ API) oil and the related difficulty in
exploiting the field’s reserves; a supporting jack-up will be on-site at
Mariner for at least four years.
The development of Mariner also reflects the change in investment
in the UKCS, with less going towards conventional developments and
more towards enhanced oil recovery (EOR), heavy oil, high-pressure
high temperature (HP/HT) and West of Shetland developments.
Projects that fall into these categories include the Bressay heavy
oil field; Captain EOR project, the Culzean HPHT field and the
Laggan-Tormore project West of Shetland. All of these projects are in
various stages of development.
Statoil is currently working on a development concept for its
Bressay heavy oil field, with a decision expected to be made before
the end of 2015 and a final investment decision expected in 2016.
This follows the abandonment of a previous development plan for
the field in late-2013. The original plan included accommodation and
processing platforms connected to an FPSO.
The Mariner and Bressay fields have benefited from new UK tax
allowances for ultra-heavy oil developments. These are categorised
as fields with oil that has an API of 18˚ API or less. This tax relief has
also been of benefit to EnQuest’s Kraken field; an FPSO development
that is scheduled to start-up in 2017. It is hoped that the new tax relief
introduced in the 2015 budget could have similar positive effects that
have been seen within these heavy oil developments.
The Captain Field first entered production in 1997 and consists of
two platforms connected to an FPSO. Operator Chevron carried out
a study to test the use of polymer chemical injection for enhanced oil
recovery at the field, which proved positive. The project will involve
an additional bridge-linked platform (BLP) to provide space for new
EOR equipment, and may require a second BLP to replace the ageing
FPSO. KBR, Amec Foster Wheeler, Wood Group Kenny and Jee have all
been involved in the early engineering and design phase of the project.
Chevron is also currently tendering for the subsea trees wellheads
and controls and has also begun a long tender process for the EOR
platform, with pre-qualification documents issued to multiple yards.
HPHTfields
Like heavy oil fields, high pressure/high temperature (HPHT) fields
have also benefitted from tax allowances, introduced in the 2014
budget. Maersk Oil’s US$4.7 billion Culzean HPHT gas and condensate
field is one such project. Culzean is to be developed through three
bridge-linked platforms comprising of a 12 slot wellhead platform
(WHP), a central processing facility (CPF) and a utilities/living quarters
platform. Produced condensate is to be exported by shuttle tanker via
a newly installed floating, storage and offloading (FSO) vessel.
Maersk has approved the project internally and is awaiting
approval from its project partners, BP and JX Nippon. Government
approval and a final investment decision is expected to take place
before the end of the year. Maersk has gone to market for the topsides
for the three platforms and for two of the jackets, but have asked
companies involved in the tender to revise their bids.
West of the Shetlands is a relatively unexplored region of the
UKCS, largely due to the inhospitable environment for hydrocarbon
exploration, but is soon to become amore integral part of UK production.
Later this year Total will start production from its Laggan and Tormore
gas and condensate fields having been delayed due to adverse weather
and staff strikes. The project is expected to produce 494million ft
3
/d at its
peak and is expected to have a field life of 30 years.
Several other projects of note on the UKCS include the HPHT
Jackdaw field, operated by BG Group. A decision on whether to enter
the front end engineering design (FEED) stage for the project is to be
