1. 18 THE PRESS AND JOURNAL
March 2016 EnergyNEWS
West of Shetland project of huge
LAGGAN-TORMORE REVIEW
The £2.5billion Laggan-Tormore pro-
ject on the UK Atlantic Frontier was
given the go-ahead in early 2010 with
the expectation that it should deliver
around 1trillion cu.ft of gas to the UK
market,plussignificantvolumesofcon-
densate for export, starting in 2014.
Like so many major projects, both
targets were missed. Operator Total
brought L-T into production last month
– some 18 month late – and the capex
bill grew to around £3.5billion.
A big chunk of the blame for this lies
with terminal construction contractor
Petrofac which apparently grossly un-
derestimatedjusthowdifficultbuilding
major infrastructure on Shetland is.
That said, this is a hugely strategic
development as it is the UK’s first ever
Atlantic Frontier gas infrastructure and
will play a very important role in do-
mestic production of this backbone,
taken for granted commodity.
L-T also signposts what is possible
when companies and, to some extent
government through fiscal facilitation
withanearly2010taxbreakdesignedto
encourage WoS gas, roll up their sleeves
and get on with it.
But let’s wind back the clock to 1986
when Shell with Britoil drilled a well
200km (125 miles) north-west of Shet-
landin600m(1,968ft)ofwater.Seeking
oil they made a gas-condensate find.
However, the 206/1-2 discovery be-
came for a time one of a number of
gas/liquids finds made on the UK At-
lantic Frontier rendered moribund due
toaperceivedlackofscalecoupledwith
technologychallengesdeemedtoohard
to handle at the time. Indeed, that par-
ticular acreage was to be relinquished.
Nine/ten years later, the licence on
which 206/1-2 was drilled was re-of-
fered via the 16th Oil & Gas Round of
1995 in which Total was awarded the
acreage as it felt there was potential.
The company got on with drilling
threefurtherLagganwells...206/1-3in
1996 to get a better initial feel for what
Shell and Britoil had encountered; then
206/1a-4a and the 206/1a-4aZ sidetrack
of 2004, which was suspended as a pos-
sible future producer, albeit commer-
cial viability remained an issue.
The 206/4AZ well tested at 37.8mil-
lion cu.ft per day of gas. Work contin-
ued on a potentially stand-alone devel-
opmentiftheeconomicscouldbemade
to work and if government assisted to
ease the way financially as the project
would involve a pipeline that others
might use at some time in the future.
Doubts were assuaged with the
205/5a-1 success when Laggan consort
Tormorewasfoundin2007.Totalatlast
had a perhaps viable development.
Driving the project forward during
its early years under Total was the
Frenchgroup’sthenUKNorthSeachief
Michel Contie, who was passionate
about WoS, who wanted to see a com-
mercial gas breakthrough in the sector
and who lobbied government inten-
sively, trying to persuade it to make a
strategic investment in gas transporta-
tion infrastructure.
Contie was unquestionably also an
important catalyst to the eventual cre-
ationoftheWestofShetlandTaskForce
(WoSTF) between the industry and the
UK Government. Its purpose was to
hammer home the strategic value of
WoS as a sub-province of the UK Con-
tinental Shelf.
Prior to Laggan-Tormore coming on-
stream last month, UK Atlantic Fron-
tier gas export infrastructure was lim-
ited to the BP-operated 20-inch West of
Shetland Pipeline System and the East
of Shetland Pipeline System which to-
gether transport associated gas from
Clair and the Schiehallion/Foinaven
fields to BP’s Magnus field East of Shet-
land for enhancing oil recovery.
Given the third-party business di-
mension to the Laggan-Tormore
pipeline, little wonder Contie applied
pressure and eventually the Treasury
got around to listening and acting.
It was in January 2010, that the then
governmentintroducedataxallowance
worth up to £160million per field to
help stimulate investment WoS.
Roland Festor, Total’s head of UK ex-
ploration and production at the time,
said the allowance would be “very im-
portant” for Laggan-Tormore.
So, what of the reservoirs and the de-
velopment plan?
Laggan is a good quality Palaeocene
gas-condensate reservoir and is a com-
bination structural/stratigraphic trap.
Its crest is 3,500m below the sea floor
and it has a 400m gas column.
The areal extent of the reservoir is
42sq.km.Totalgrossreservoirthickness
(T35 sands) is less than 70m (including
two field-wide inter-bedded shales).
The reservoir comprises sand-rich
turbidite lobe facies, with the reservoir
architecture controlled by compensa-
tion and normal faults.
Tormore resembles Laggan in terms
of trapping configuration, depositional
model and reservoir properties. The
main difference is the fluid, with Tor-
more gas condensate being about three
times richer than Laggan. The reservoir
lies at a depth of 5,505m (crest).
The fact that Tormore is richer than
Lagganwasofconsiderableimportance
in terms of commerciality as that “wet-
ness” helped swing the viability pendu-
lum in the right direction.
It is located some 16km south-west of
its neighbour and had for some years
been recognised as a potential gas re-
source by the licence partners.
In parallel to the activities of the
WoSTF talks, the Tormore partners put
together a plan to drill the prospect in
summer 2007 using the Sedco 714 rig.
That well spudded on June 13, 2007,
andtotaldepthwasreachedinlessthan
twomonthsonAugust3.Afterfinallog-
ging a drill-stem test was performed.
Accordingtoapaperpreparedforthe
Society of Petroleum Engineers by To-
tal, the discovery in Tormore of appre-
ciable further quantities of gas conden-
sate close to Laggan brought a welcome
boost to the WoSTF and “put the ball
firmly back in the court for the Laggan-
Tormore partners to push forward with
their plans to open up a new gas export
infrastructure for the region”.
After preliminary studies confirmed
the potential economic value of a com-
binedproject,thepartnershipagreedto
move forward with an aggressive
schedule of development studies aimed
at selecting the optimum development
concept by mid 2008.
Departing from the conventional se-
quence of conceptual studies followed
by pre-project, it was agreed to update
the original standalone Laggan pre-
project to take account of Tormore
while in parallel running an offshore
hub conceptual study.
Three options were considered:
● Onshore hub: a long distance subsea
tie-back of more than 140km to a new
onshore gas processing plant close to
the existing BP-operated terminal at
Sullom Voe;
● Shallow water hub: a subsea tie-back
to a new platform in 150m water depth
on the shelf close to the existing BP-op-
erated Clair platform;
● Deepwater hub: a subsea or dry tree
tie-back to a floating TLP (tension-leg
platform) or deep draft semi-sub-
mersible moored in 600m close to the
sister fields.
According to the SPE paper, the later
inclusion of Tormore did not have a sig-
nificanteffectonthefindingsoftheear-
lier environmental screening studies.
In the event, the decision was made
to develop Laggan-Tormore based on a
subsea package offshore, tied back via
two multiphase flowlines to a shore-
basedprocessingplantlocatedatSullon
Voe in Shetland and which would be
built with spare capacity to enable fu-
ture tie-ins from other projects. Indeed
L-T has set a new UK record for subsea
tie-backs to the beach.
Export from the gas plant at Sullom
Voe would connect to the existing
FUKA line in the northern North Sea,
which in turn feeds into St Fergus ter-
minal for final processing into sales gas
and commercial export.
Condensate would be separated from
the gas during processing at the new
Shetland facility, then stabilised and ex-
ported by tanker from existing BP fa-
cilities at Sullom Voe.
The gas production plant would be
designedtoprocess500millioncu.ftper
daygas,plusassociatedcondensate(de-
sign rate 27,900 barrels per day).
To take account of future third party
gas production the export facilities will
at some point in the future be upgraded
for up to 665million cu.ft per day. The
export line is already sized to take ac-
count of this additional requirement; a
wisedecisionbearinginmindthatTotal
has already initiated developments of
nearby Glenlivet and Edradour.
The key reason behind opting for a
subsea tie-back to the beach with all op-
erations staff being shore-based is
safety. However, it also facilitates access
for third parties to the regional gas
transportationsystem;andasubseatie-
back to shore, with the addition of sub-
sea compression in late field life, will
Operator Total brought Laggan-Tormore into commercial
production last month, writes Jeremy Cresswell as he charts
something of the history of the UK’s first Atlantic Frontier
natural gas production infrastructure
Above: The gas terminal and, below, the MEG treatment area

2. THE PRESS AND JOURNAL
March 2016Energy 19NEWS
strategic importance to Britain
allow maximum recovery of reserves.
An elegant if challenging solution.
There is also the issue of the physical
environment . . . another good reason
why the subsea/onshore approach was
selected. The water current patterns in
the vicinity of the sister fields are com-
plex with various strong non-tidal cur-
rents interacting with relatively weak
tidal flow.
On the surface, the deep water over
the West of Shetland continental slope
is exposed to a large oceanic fetch and
strong winds, particularly from the
west and south-west. These conditions
can generate an extreme wave regime
that is more severe than that experi-
enced in the Northern North Sea. The
area is also affected by long periods of
ocean swells generated from Atlantic
storms.
It was planned that drilling opera-
tions at Laggan-Tormore would be car-
ried out in two phases. To facilitate this,
a six-slot template-manifold was lo-
cated on the seabed at each of the Lag-
gan and Tormore locations.
Under phase one, three new wells
were drilled at Laggan plus re-entry of
one of the existing wells; together with
one new well at Tormore.
Further wells are planned and will be
located optimally following the review
of year one production data.
The well suite is controlled via an
electro-hydraulic umbilical, which in-
cludes cores for the transport and in-
jection of chemicals (scale, corrosion
and wax inhibitor) as well as methanol
for start-up purposes.
Now that L-T is onstream, Total and
assetspartnersDONGandSSEarehop-
ing for peak production rates of at least
90,000 barrels oil equivalent per day.
Output is then expected to decline
graduallyovertimethroughnaturalde-
pletion of the reservoirs. This will to an
extentbecounteredbytheuseofsubsea
compression though this was not a part
of the original development plan.
As for future additions to L-T infras-
tructure, that has already started with
field development plans for the
Edradour/Glenlivet project approved
by government last year. The original
decision to invest in this was taken by
Total in May 2014.
The Edradour field is located on
block 206/4a, in some 300m of water.
The development plan consists of the
conversion of the discovery well into a
productionwellanda16kmproduction
pipeline tied back to the main Laggan-
Tormore flowline.
Edradour is expected to start up in
Q4 2017 and to reach a plateau of 17,000
barrels oil equivalent per day.
Glenlivet is located on block 214/30a,
in 435m of water and will be developed
with two wells using a single four-slot
manifold on the seabed and a 35km
pipeline tied back to the Laggan-Tor-
more production flowline.
FirstgasisexpectedinQ32018andto
plateau at 21,000boe per day.
And thus begins Total’s third and
frontier-busting production hub in UK
waters . . . another source of domestic
gas that should help keep our hydro-
carbons imports bill at bay.
The long-term hope is that further
gas discoveries will be tied in and that
the infrastructure is extended.
Total E&P UK operates Laggan-Tor-
more with a 60% interest alongside
partners DONG E&P (UK) Limited
(20%) and SSE E&P UK Limited
(20%).
The mighty task of 2,700 workers to pioneer first UK Atlantic Frontier gas infrastructure
Simon Hare –
West of Shetland
asset manager
The industry had been looking at how
to extract gas from West of Shetland for
decades. When I first joined Total in
the mid-1990s, it was involved with a
group of companies on what was called
the Aurora project.
At that time, we were looking at joint
industry strategies to develop both oil
and gas in the region. That was a period
when the industry was doing a lot of
drilling West of Shetland.
History obviously speaks for itself in
that, at that time, there were no major
gas discoveries made. The Aurora
initiative didn’t go anywhere.
Two decades on and with Total
involved, we got to a point where,
thanks to the discovery of Laggan way
back and Tormore more recently,
there was sufficient critical mass to
justify a commercial development.
So what is the significance? It’s
thanks to this development that we
now have a terminal and a gas
pipeline that runs right out to the
heart of the West of Shetland area;
and that provides a backbone for
Total’s own developments – current
and future – and clearly too, future
developments by other operators.
Margaret Muir –
Laggan-Tormore
services manager
Prior to becoming involved with
Laggan-Tormore, I had been in the
company for more than 15 years. With
this project, Total needed someone to
join that team and set up project
services . . . cost control, HR,
planning, contracts, logistics and IS
. . . the systems side.
We’re the ones who have kept
everything running smoothly and at
the right time; back office stuff. The
big challenge of my role was the sheer
number of people involved . . . around
2,700 at peak.
We had a team of 250 people
representing just Total on the project.
And the contractors . . . like Subsea 7
and Petrofac, which had their own
workforces, had to liaise with us. We
had an HR team dedicated to making
sure that the relationships between
Total and the different contractors
worked smoothly.
This included making sure the
workforce travelled to and from
Shetland safely, that they had all the
right accommodation; things like that.
There’s been a lot of work going on
behind the scenes to make sure all of
this worked smoothly.
When you bring 2,700 people into a
small community like Shetland it was
inevitable that there would be issues.
But we had a really good relationship
with Petrofac, which was responsible
for seeing that any actions agreed
were seen through.
David Hainsworth –
UK operations manager
Personally, I was involved early on
in the project to help define the
operating philosophy, once it was
decided that it was going to be a
subsea development with a long
tieback.
Norwegian projects Ormen Lange
and Snohvit with their subsea
infrastructure and onshore facilities
helped Total towards its decision to
opt for a long subsea tieback direct
to infrastructure onshore.
Clearly, if the platform route had
been taken, there would potentially
have been the opportunity to lower
wellhead pressures in late field life.
Equally, we now know from other
developments that there are other
potential ways of doing this, such as
subsea compression, that could
come along in the future to achieve
the same thing.
Also, by going subsea, most of the
year we don’t need to be offshore
and that delivers safety benefits. It’s
an elegant solution that works well
with gas.
As for having an operations
centre onshore, that brings
significant safety advantages and we
have space. We can easily have big
equipment like gas compression
with waste head recovery systems.
These are hard to fit aboard
platforms; much easier onshore
where we have much more space.
The first challenge we have now
that we’re operational is to keep the
plant full. We have really good
infrastructure; we have a very large
plant with a lot of capacity that will
give us flexibility in the future so
similar wet gas developments can
be tied into the system at very little
cost.
That’s why Edradour-Glenlivet
can be made economic.
Aerial view of Laggan-Tormore gas terminal