Expanded Abstracts - Exploration Revived 2013
Expanded Abstracts - Exploration Revived 2013
Expanded Abstracts - Exploration Revived 2013
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Abstract
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Programme committee
Abstract:
The NPD has revised its resource estimates and quantified the total expected undiscovered
recoverable resources at 2590 million standard cubic metres (Sm3) of oil equivalents (o.e.).
The table below shows the numbers and uncertainty range.
P90
Expected
3
P10
3
mill/bill Sm
mill/bill Sm
mill/bill Sm3
Liquid
630
1400
2450
Gas
525
1190
2100
Total
1290
2590
4400
The previous estimate from 2010 was 20 million Sm3o.e. lower. Approximately 270 million
Sm3 o.e. have been discovered since the previous estimate which means that the NPD has a
more positive view on the undiscovered potential than before.
In the North Sea, the southern part of the Utsira High and the Tampen Spur area account for
the most significant resource estimate changes. The Johan Sverdrup discovery, located on the
southern part of the Utsira High, indicates that there is more oil and less gas in the area than
estimated in 2010. A new play has been defined which reflects this better than previous plays.
As regards the Barents Sea, undiscovered oil resources have been adjusted upwards, and gas
resources have been decreased. This is mainly due to a changed perception of the possibility
of finding oil in the area around Skrugard.
The estimate for the Norwegian Sea has not changed appreciably.
The resource estimates cover the same geographic area as the analysis from 2010 and
previous analyses and does not include the Norwegian part of the previously area with
overlapping claims in the Barents Sea south-east and the waters off Jan Mayen.
During the summers of 2011 and 2012 the NPD accomplished a successful acquisition of 2 D
seismic in the new Norwegian areas in the Barents Sea and on the Jan Mayen Ridge. In 2012
2 D seismic was aquired off the coast of Helgeland. In these areas about 48 000 km of
seismic lines were acquired. In the north eastern part of the the Barents Sea the acquisition
will continue this summer.
Based on the seismic data acquired the NPD has evaluated the petroleum potential and
estimated the undiscovered resources in the southern part of the new area in the Barents Sea
and on the Jan Mayen Ridge. These new estimates are input to the White Paper that is
planned to be forwarded to the parliament before this summer.
Biennial Geophysical Seminar 4 Biennial Geophysical Seminar
The seismic data that has been acquired off the coast of Helgeland is a part of the
governments Kunnskapsinnhentingen in the northeastern part of the Norwegian Sea. The
result of the evaluation of these data will be presented later this year.
Abstract:
Skrugard A Breakthrough in the Barents Sea
Bjrn Lindberg (presenter) & Skrugard Exploration Teams in Statoil, Eni Norge & Petoro
Expectations and activity levels have varied considerably since the Barents Sea was opened for
exploration more than 30 years ago. The first discoveries in the Hammerfest Basin (Askeladd, 1981)
caused great optimism, which turned to disappointment and pessimism towards the late 1980s;
discoveries were mainly gas with low commercial value at the time, a dramatic drop in oil price and dry
wells on large structures outside the Hammerfest Basin. After a period of no wells in the late 1990s, the
Goliat discovery in 2000 caused renewed optimism and was the first commercial oil discovery in the
Barents Sea. However, there were still no discoveries of sufficient size for new infrastructure outside of
the Hammerfest Basin.
The PL532 license, regarded as the 20th round golden blocks by the industry, was awarded to Statoil
(Operator, 50%), Eni Norge (30%) and Petoro (20%) in May 2009. Skrugard was classified as an impact
prospect (> 250 mmboe) and became a prioritized drilling candidate for 2011.
The Skrugard discovery in April 2011 represented a breakthrough for exploration activities in the Barents
Sea, and was labeled the most important discovery in ten years on the Norwegian shelf. The discovery
was a result of experience, perseverance, and team work. Up until the discovery, Statoil had participated
in all 87 exploration wells, and operated ~64 of these. Partners Eni Norge and Petoro have also been
among the few stayers with continuous exploration activity in the Barents Sea.
Less than nine months after the Skrugard discovery, the Havis discovery in a neighbouring structure was
made, totaling the proven recoverable oil volumes to 400-600 mmbls in addition to the gas caps. A field
development project was established shortly after the Skrugard discovery, and is presently in the
concept selection phase.
The Lower Middle Jurassic play was unproven in the Bjrnya Basin/Bjrnyrenna Fault Complex until
the Skrugard well was drilled. In the nearby well 7219/9-1 drilled by Norsk Hydro in 1988, there were
good oil shows in the St and Nordmela Formation sandstones, indicating that this structure failed due
to leakage. The trap seal was therefore considered to be the main risk prior to drilling. The Skrugard
discovery well confirmed the top and lateral seal provided by the Fuglen and Kolmule/Kolje formations,
and that these can hold >150 m hydrocarbon column with an overburden of < 900 m.
The Skrugard well proved the presence of a good to excellent reservoir in the St, Nordmela and Tuben
formations. Also in the Fruholmen and the uppermost Snadd formations good sandstones were
encountered, suggesting these formations to be potential reservoirs elsewhere.
The entire license area is covered with 3D seismic. Direct Hydrocarbon Indicators (DHIs), prominent on
Skrugard, present on Havis, and, in hindsight, somewhat more dubious on the dry 7219/9-1 structure
were recognised. As such, important calibration points for the geophysical observations are established.
DHIs of varying strength and confidence have also been identified in numerous other structures within
the license boundaries. These include flat-spots, amplitude conformance, intra-reflectivity brightening,
and AVO anomalies.
On the basis of the seismic assessment, prospect ranking was performed and decision to drill Skrugard
was made. Before the Skrugard well was drilled in 2011, EM resistivity images of the subsurface across
the Skrugard prospect were obtained and used by Statoil for estimations of the hydrocarbon saturation.
The resistivity distribution was derived from extensive data analysis of multi-client CSEM data from
2008. After the discovery, prospect specific CSEM data was acquired on a proprietary basis by Statoil,
and the data was used for calibration of discoveries.
The discoveries need to be seen in light of the exploration history in the Barents Sea, and are important
for several reasons; as new reserves for the involved companies, establishment of new infrastructure,
and to remove some of the myths linked to the Barents Sea as an exploration province dominated by
fatal leakage and gas only. In addition, the Bjrnya Basin with neighbouring areas had, prior to the
Skrugard discoveries, several dry wells making it empirically the area with lowest success in the Barents
Sea. Discoveries in this area increase expectations that adjacent areas can contain commercial potential.
A second exploration wave is planned for the area and will target four wells, starting with the Nunatak
prospect with reservoir of Cretaceous age. The subsequent three prospects are of Jurassic age and of
varying depth, volume and probability of success, and will all in a success case be a part of the
Skrugard/Havis development.
Fig. 1: Regional overview of Barents Sea with Top St depth map, showing the location of the Skrugard
and Havis discoveries within the Bjrnyrenna Fault Zone on the western flank of the Barents Sea.
Structural elements from Norwegian Petroleum Directorate.
Fig. 2: Semi-regional map of Top St Fm depicting the faulted terrace setting in which the discoveries
were made.
Fig. 3: Seismic line with overlain interpretation and stratigraphic units crossing the Skrugard and Havis
discoveries as well as the structure on which the dry 7219/9-1 well was drilled. Seismic courtesy of
WesternGeco.
Figure 4: Vertical resistivity section through the Skrugard well (left panel) and the 7219/9-1 well (from
Nordskag et al. 2013)
Nordskag, J. I., Kjsnes, ., Hokstad, K. and Nguyen, A. K. [2013] CSEM in the Barents Sea, Part III: Joint
interpretation of CSEM and seismic inversion results. Submitted to 75th Annual International Meeting,
EAGE, Expanded Abstract.
Abstract:
Lundin
Norway
has
actively
explored
the
area
on
and
around
the
Loppa
High
since
the
award
of
Lundins
first
exploration
license
in
the
Barents
sea
in
2007.
A
large
number
of
plays
have
been
investigated
and
matured,
spanning
from
basement
to
Paleogene.
The
presentation
will
give
an
overview
of
relevant
geological
elements
and
plays
in
the
area
seen
from
Lundin
Norways
perspective.
Vesllemy High,
H
Barrents Sea
a: Geology and P
Plays
Janne Guttormseen, Noem T
Tur, Micheele Comisso
o, Pieter Peestman
Repsol
R
Explloration No
orge AS, Osslo
Introoduction
The V
Veslemy High
H
is locateed in the weesternmost portion
p
of thee Barents Seea, in-betweeen the
Trom
ms Basin to the SE, and
d the Srvesttsnaget and Bjrnya baasins to the N
NW (Figure 1). It
actuaally is a paleoo-high, activee during the latest Cretacceous and earrliest Tertiary
ry (Figure 2).
The C
Cretaceous iin the westerrnmost Barennts Sea is ch
haracterized by a series of faulted blocks.
b
Barents Seaa became a passive
Afterr the breakupp of Scandinaavia and Greeenland, the westernmost
w
margin characterrized by pro
ograding seddimentation during
d
the Tertiary
T
andd Quaternary
y. The
Cretaaceous and Tertiary meegasequencess are separaated by a major
m
unconfformity, the Base
Tertiaary Unconfoormity (BTU
U). In placess (such as th
he Veslemy
y High), thiss unconform
mity is
clearlly angular, reeflecting uplift due to loccalized comp
pressional conditions.
Licennse PL531, currently
c
opeerated by Reppsol Exploraation Norge AS,
A is locateed on the sou
uthern
portioon of the Veeslemy Hig
gh, covering a structure that,
t
at the level
l
of the B
BTU, has a dome
shapee (Figure 3). The present paper focusees on this po
ortion of the Veslemy
V
H
High.
Untill now, the Veslemy High
H
has noot been drillled. An exp
ploration weell, 7218/11-1, is
schedduled to be spudded
s
in February
F
20113 on PL531. Reference wells includde 7219/8-1 S (the
closest well, at 466 km distancee), 7216/11- 1 S, and 7316/5-1.
Figurre 1. Locatio
on map, show
wing referencce wells and discoveries/f/fields.
Tectoonic Setting
Evenn though the Veslemy
V
High is considdered to be an antiform shaped by thhe BTU, theere are
t Veslemy Anticlinee as a multi--event
good structural-geological evidences for cconsidering the
structture:
L
Late Cretaceoous syn-kineematic episodde: listric shaallow rooted faults affectting the early
y Late
C
Cretaceous seequences on the top of thhe structure.
P
Post-kinematic latest Crretaceous eevent, resultiing in general truncationnal attitude of the
B
BTU throughhout the antiicline (as thhe Upper Creetaceous seq
quences are supposed to
o have
bbeen eroded)..
E
Early Paleoceene syn-kinematic episodde: progressiv
ve onlapping
g of Lower PPaleocene strata on
eeastern limb of
o the structu
ure.
L
Late Paleocenne post-kinem
matic episodde: no activity
y (or very mild activity).
E
Eocene syn-kkinematic episode: progrressive erosio
on of the BT
TU on the w
western limb of the
sttructure.
The seismic imaaging is verry poor on the deeper section but it is possib
ible to supp
pose a
decouupling of thee structuration from the vvery defined geometries
g
of
o the overlyiing section. In
I this
case, the heavilyy rotated fau
ulted blocks on the top of
o the structture should correspond to the
zonee of tension of a glideed system w
while there arre, up to no
ow, no clearr evidences of
o the
expeccted toe coompression. This impllies a region
nal detachm
ment slightlyy above the Base
Cretaaceous Unconnformity (BC
CU; in some areas, the BCU
B
itself is acting as a ddecollement level):
l
the B
BCU is separaating two diffferent rheoloogical system
ms.
Whilee the re-acttion throug
gh gliding is clearer, thee nature of th
he action giving rise to the
Vesllemy Anticcline is stilll uncertain: deeply-rootted (obeying
g to rejuvennated old reg
gional
trendd affecting thhe Caledoniides) or shaallow detach
hed (obeying
g to the rheeological partition
suggeested by the gliding)? Orr a combinatiion of the two?
Accoording to thee ongoing reegional interp
rpretation, th
he pre-existin
ng shapes off the Caledo
onides
(napppe geometriees) are playin
ng a major roole in the evo
olution of thee structure: thhe Veslemy
y High
is oveerlying a pree-Jurassic bassement high..
Figure
F
3. Map
ap of Base Teertiary (BTU)
U).
m
Playss and Petrolleum System
Two plays have been
b
identifieed on the Ve slemy High
h (Figure 2):
Cretaaceous turbidites in halff-grabens unnderneath th
he BTU. Thee trap is part
rtly structuraal, and
partlyy stratigraphic (truncation
n against thee BTU). If th
he turbidites are Aptian-A
Albian in age, this
wouldd correspondd to the NPD
Ds bju,kl-3 play. If they
y turn out to
o be Late Cre
retaceous in age, a
new pplay name would
w
be requ
uired, e.g. bkku-2.
urbidite sanndstones), on
nlapping thee BTU. Thee trap is bassically
Paleoocene beds (probably tu
stratiggraphic, withh a structuraal componennt. This is a new play: a Paleocene version of NPDs
N
beo-11 play.
Unceertainties exisst regarding the petroleum
m systems off these plays:
Soource rock and
a
timing. The only pproven sourrce rock in the area, thhe Upper Ju
urassic
Hekkingen Foormation, is currently ovvermature ov
ver most of the
t area arouund the Vesllemy
Hiigh; most off the hydrocaarbon expulssion may hav
ve occurred before
b
trap fformation. Several
Crretaceous an
nd Paleogene source rockks are known, but it is nott clear how th
they are deveeloped
inn the surrounddings of the Veslemy H
High.
Reeservoirs. Thhe targeted intervals, Palleocene and Middle-Upp
per Cretaceouus, do not co
ontain
saandstones in any of the reference w
wells. The best analoguees for the foormer are Eocene
E
saandstones in wells 7216/1
11-1 S and 77316/5-1, wh
hile for the laatter, Cretaceeous sandstones in
M
Mid-Norway and
a the north
hern Hammeerfest Basin may
m be used as analoguess.
The Caurus discovery, Barents Sea A new look at the middle Triassic Kobbe formation
Camilla Oftebro and Carsten Elfenbein, Det Norske ASA
Introduction
PL659
Caurus,
awarded
February
2012
(APA
2011),
is
located
on
the
Bjarmeland
Platform.
It
is
defined
as
a
footwall
uplift
structure
situated
along
the
northern
part
of
the
Asterias
fault
complex,
and
includes
the
Caurus
discovery
(well
7222/11-1T2)
made
by
Statoil
in
2008
in
production
license
PL228.
Det
norske
is
the
operator
of
PL659
and
the
licensees
are
Petoro,
Lundin
Petroleum,
Spring
(now
Tullow
oil),
Rocksource
and
Valiant
Petroleum.
A
firm
well
is
planned
in
Q4
2013
and
3D
seismic
acquisition
is
planned
in
2014/2015.
Figure1:
Location
of
PL659.
Well
7222/11-1
was
drilled
with
the
objectives
to
prove
hydrocarbons
in
the
Triassic
Snadd
formation
and
in
the
Middle
Triassic
Kobbe
Formation.
The
well
proved
gas
in
channelized
sandstones
of
the
Snadd
Formation
with
a
gas-water
contact
and
also
gas
and
oil
at
two
levels
in
the
Kobbe
Formation
(Anisian);
oil
in
an
Upper
Anisian
reservoir
and
gas
and
oil
in
a
lower
Upper
Anisian
reservoir.
The
discovery
was
considered
sub-commercial
and
the
license
was
relinquished
in
2010.
The
Kobbe
Formation
reservoir
in
the
discovery
well
on
Caurus
encountered
low
net
to
gross
ratios
and
generally
poor
porosity
and
permeability.
The
same
marginal
reservoir
quality
is
seen
in
other
wells
in
the
Bjarmeland
area.
Hence
the
reservoir
potential
of
the
Kobbe
Formation
has
commonly
been
perceived
as
limited.
In
2011
the
gas
discovery
well
7225/3-1
on
the
Norvarg
Dome
delivered
encouraging
production
test
results
from
an
interval
which
is
directly
correlatable
to
the
main
reservoir
in
Caurus
well
7222/11-1.
This
lead
to
a
re-evaluation
and
a
more
positive
view
of
the
production
properties
of
the
Kobbe
Formation
on
Caurus.
In
addition,
recent
results
from
other
wells
in
the
area
and
in
particular
conclusions
after
seismic
special
studies
spectral
decomposition/RGB
blending,
seismic
inversion,
and
AVO,
gives
reasons
to
believe
that
the
Kobbe
formation
may
have
substantial
commercial
potential.
Play
summary
The
Caurus
structure
developed
during
the
Jurassic
early
Cretaceous
by
footwall
uplift
along
the
north-eastern
flank
of
the
Asterias
fault
complex,
the
fault
that
separates
the
Bjarmeland
Platform
from
the
Hammerfest
Basin.
The
main
resource
potential
within
the
license
is
situated
within
the
large
Caurus
three
way
dip
closure
in
the
Anisian
Kobbe
formation,
fault
bounded
by
the
Asterias
Fault
Complex
towards
southeast(
figure
2).
Figure
2:
Top
Kobbe
depth
structure
map
with
spill
contour
outlined
in
white.
The
younger
Carnian
Snadd
Formation
with
its
channelized
sandstone
reservoirs
is
considered
an
upside
potential.
The
Triassic
evolution
of
the
area
is
dominated
by
seismic-scale
prograding
transgressive-regressive
sequences
sourced
mainly
from
the
Uralides,
possibly
with
minor
contribution
from
Fennoscandia.
The
main
reservoir
of
the
Kobbe
Formation
is
composed
of
sandstones
and
heteroliths
deposited
in
shallow-
to
marginal
marine
settings
during
Anisian
time.
These
include
tidal
channels
and
bars,
bayfill
and
fluvial
distributaries.
At
this
stage
it
is
too
early
to
conclude
on
the
trapping
and
sealing
mechanism
of
the
reservoir.
It
is
assumed
that
the
Asterias
Fault
Complex
behaves
as
a
sealing
fault
for
the
3-way
dip
closure,
and
robust
top
and
base
seals
are
provided
by
extensive
shale
intervals
representing
flooding
surfaces.
MDT
pressure
points
from
the
hydrocarbon
zone
in
the
Kobbe
Formation
in
well
7222/11-1
show
no
connectivity
between
the
two
different
Anisian
reservoir
zones.
Also,
the
well
proved
hydrocarbons
down
to
a
depth
that
is
about
140m
deeper
than
the
mapped
spill
at
Top
Kobbe
level.
Hence
multiple
stacked
reservoir
zones
seem
likely,
and
the
modest
hydrocarbon
columns
encountered
by
the
well
could
be
controlled
by
local
stratigraphic
(or
structural)
traps.
The
Kobbe
Formation
gas
play
is
assumed
sourced
from
the
underlying
and
inter
fingering
organic-
rich
mudrocks
of
the
Klappmyss
and
Kobbe
formations.
From
3D
seismic
data,
numerous
channel
features
are
mapable
at
different
stratigraphic
levels
within
the
Kobbe
Formation.
Spectral
decomposition
techniques
reveal
a
network
of
sinuous,
relatively
narrow
channels
on
the
one
hand
and
wider
and
straighter
channels
on
the
other
hand.
The
latter
possibly
indicating
a
relatively
sand
prone
distributary
channel
system.
Examples
from
spectral
decomposition
are
shown
in
figure
3.
Especially
two
big
channel
geometries,
the
Langlitinden
prospect
and
the
Sntinden
prospect,
are
clearly
distinguished
and
are
considered
as
the
two
main
prospects
in
the
Kobbe
formation.
Figure
3:
Examples
of
seismically
visible
channels
at
different
levels
in
the
Kobbe
formation
from
spectral
decomposition
analysis
(RGB
blend).
72
70
68
66
20
25
Troms
15
TROMS II
Hars t ad
20
Nar vik
Bod
NORDLAND VII
10
15
NORDLAND VI
10
Location Map
The
Lofoten
crystalline
basement
rocks
represent
structural
highs
surrounded
by
sedimentary
basins.
The
most
prominent
high
is
the
Lofoten
Ridge.
To
the
west
of
the
Lofoten
Ridge
is
the
Ribban
Basin.
This
basin
is
filled
with
sedimentary
rocks
of
Jurassic
and
Cretaceous
age.
North
of
the
Lofoten
Ridge
is
the
Harstad
Basin,
characterized
by
strong
subsidence
in
the
Jurassic
and
Cretaceous.
The
basin
is
0
5
68
66
Location Map
OD 1302005
Location
Map
The
Lofoten
crystalline
basement
rocks
represent
structural
highs
surrounded
by
sedimentary
basins.
The
most
prominent
high
is
the
Lofoten
Ridge.
To
the
west
of
the
Lofoten
Ridge
is
the
Ribban
Basin.
This
basin
is
filled
with
sedimentary
rocks
of
Jurassic
and
Cretaceous
age.
North
of
the
Lofoten
Ridge
is
the
Harstad
Basin,
characterized
by
strong
subsidence
in
the
Jurassic
and
Cretaceous.
The
basin
is
filled
with
a
thick
sedimentary
sequence
of
Cretaceous
age.
Fault
blocks
were
formed
in
the
area
in
the
Triassic
and
Jurassic,
and
reactivated
in
the
Cretaceous
and
Paleogene.
The
potential
reservoir
rocks
in
the
area
consist
of
Triassic,
Jurassic,
Cretaceous
and
Paleogene
sandstones.
It
is
also
possible
that
fractured
and
eroded
basement
can
have
reservoir
properties.
The
main
source
rock
for
oil
and
gas
in
the
area
is
of
Late
Jurassic
age.
The
source
rock
is
assumed
to
be
sufficiently
deeply
buried
to
expel
hydrocarbons
in
the
Ribban
and
Harstad
Basins.
Coastal
areas
of
the
northern
part
of
Nordland
County
and
southern
part
of
Troms
County
were
subjected
to
an
extensive
uplift
and
subsequent
erosion.
This
uplift
took
place
from
Late
Cretaceous
to
Neogene.
As
a
consequence
of
the
uplift,
the
continental
margin
was
strongly
tilted
down
towards
the
west.
Some
pre-existing
faults
were
passively
tilted,
some
were
reactivated
or
inverted.
The
strongest
tilt
occurs
where
the
margin
is
the
narrowest.
Sediment
transport
postdating
the
uplift
was
directed
towards
the
south
and
the
north
of
Lofoten,
indicating
that
this
area
remained
topographically
high.
Many
identified
prospects
are
located
in
uplifted
areas.
This
may
have
led
to
increased
leakage
of
hydrocarbons
from
the
traps.
In
this
talk,
an
overview
of
the
petroleum
geology
will
be
presented
including
the
geological
and
geophysical
challenges
that
were
part
of
the
evaluation.
Title: Finding Arctic Oil Giants: How to risk Barents Sea uplift and erosion ?
Title: Finding Arctic Oil Giants: How to risk Barents Sea uplift and erosion ?
Authors:
Maersk Oil New Ventures Exploration Team, Stavanger, Norway
Authors:
Maersk
Oil New
Ventures
Exploration
Team, Stavanger, Norway
Presenter:
Paul Henry
Nadeau,
Maersk
Oil Norway
AS, Norway
Presenter:
Paul Henry Nadeau, Maersk Oil Norway AS, Norway
Abstract: Exploration challenges in sedimentary basins which have undergone significant
challenges
in sedimentary
basinsrock
which
have undergone
significant
amountsAbstract:
of uplift Exploration
and erosion (U&E)
include:
arresting source
maturation,
reduction
of
amounts
of
uplift
and
erosion
(U&E)
include:
arresting
source
rock
maturation,
reduction
of
reservoir pressure and temperature, gas expansion, reduction of confining stress, and seal/trap
reservoir
pressure particularly
and temperature,
confining
stress, and seal/trap
failure. These
challenges,
alonggas
the expansion,
structurallyreduction
complex of
Barents
Sea margin
failure.
These
challenges,
particularly
along
the
structurally
complex
Barents
(Figure 1) require that both the magnitude as well as the timing of U&E events in the Sea margin
(Figurehistory
1) require
that both the
magnitude
as well as the
of U&E
events in the
burial/thermal
be accurately
estimated
and integrated
intotiming
petroleum
systems
burial/thermal
history
be
accurately
estimated
and
integrated
into
petroleum
systems
considerations. Such analyses often show that trap preservation with respect to hydrocarbon
considerations.
analyses
often show
that trap
with respect to hydrocarbon
charge becomes
a majorSuch
risk factor.
Geological
models
for preservation
oil and gas entrapment
charge
becomes
major risk
models for
oil and
gas entrapment
demonstrate
that
the vastamajority
of factor.
reservesGeological
occur in relatively
narrow
depth
intervals,
demonstrate
that
the
vast
majority
of
reserves
occur
in
relatively
narrow
depth
intervals,
mainly determined by the geothermal gradient and maximum reservoir temperature
(Bjrkum
mainly
determined
the 2005;
geothermal
gradient
maximum
temperature
and Nadeau,
1998;
Nadeau by
et al.,
Nadeau,
2011).and
Applying
this reservoir
methodology
to the (Bjrkum
and
Nadeau,
1998;
Nadeau
et
al.,
2005;
Nadeau,
2011).
Applying
this
methodology
to the
Barents Sea shows a clear depth interval which includes the bulk of discovered reserves.
Barents Sea
shows
a clear
includes
the bulk
of discovered
reserves.
When calibrated
to the
North
Sea, depth
as wellinterval
as datawhich
from other
basins,
the analysis
provides
a
When
calibrated
to
the
North
Sea,
as
well
as
data
from
other
basins,
the
analysis
provides
a
conceptual framework for risking Barents Sea prospects & plays for trap/seal failure, phase,
conceptual framework for risking Barents Sea prospects & plays for trap/seal failure, phase,
and preservation.
and preservation.
References:
References:
Bjrkum, P.A. & P. H. Nadeau, 1998, Temperature controlled porosity/permeability reduction, fluid
Bjrkum,
P.A. & exploration
P. H. Nadeau,
1998, Temperature
reduction, fluid
migration,
and petroleum
in sedimentary
basins. controlled
Australian porosity/permeability
Pet. Prod. & Expl. Assoc.
and petroleum exploration in sedimentary basins. Australian Pet. Prod. & Expl. Assoc.
Journal, migration,
38, 453-464.
Journal, 38, 453-464.
Nadeau, P.H., 2011, Earth's energy "Golden Zone": A synthesis from mineralogical research. Clay
P.H., 2011, Earth's energy "Golden Zone": A synthesis from mineralogical research. Clay
Minerals,Nadeau,
46, 1-24.
Minerals, 46, 1-24.
Nadeau, P.H., Bjrkum, P.A. & Walderhaug, O., 2005. Petroleum system analysis: Impact of shale
Nadeau,
P.H., Bjrkum,
P.A. &
Walderhaug,
O., 2005.
Petroleum
systemrisks.
analysis:
Impact
diagenesis
on reservoir
fluid pressure,
hydrocarbon
migration
and
biodegradation
In: Dor,
A.of shale
diagenesis
on Petroleum
reservoir fluid
pressure,
hydrocarbon
migration
and biodegradation
risks. In: Dor, A.
G. & Vining,
B. (eds)
Geology:
North-West
Europe
and Global
Perspectives Proceedings
& Vining,Geology
B. (eds)Conference,
Petroleum Geology:
North-West
andConferences
Global Perspectives
Proceedings
of the 6thG.Petroleum
1267-1274.
PetroleumEurope
Geology
Ltd.,
thethe
6thGeological
PetroleumSociety,
GeologyLondon.
Conference, 1267-1274. Petroleum Geology Conferences Ltd.,
Publishedofby
Published by the Geological Society, London.
Figure 1. Structural geo-seismic section along the Western Barents Sea Margin (J. K.
Hansen, pers. com.)
The effort resulted in: 3 significant commercial discoveries (Tyrihans, Heidrun and Aasta
Hansteen) representing a NPD estimated gross recoverable resource base of 360 MM SM3; three
technical discoveries with an estimated challenged in-place resources in excess of 550 MM SM3
(Ellida, Midnattsol and Stetind); fourteen wells with significant shows and fourteen dry holes.
Each of these wells played a significant role in advancing the geologic understanding of the Mid
Norway region. This paper provides a look back on the exploration program with the intent of
compiling the lessons learned into a meaningful geologic synopsis that will hopefully prompt
discussion and benefit industry in future exploration efforts.
The Haltenbanken area was opened for initial (5th Round) license applications in 1980. Midgrd
(later part of sgard unit) was discovered in 1981 but was viewed at the time as a disappointment
(gas-condensate). Two years later ConocoPhillips was part of the consortium that made the first
oil discovery in the area (Tyrihans). Encouraged by this result the company initiated extensive
regional work in preparation for the 8th Licensing Round. A key part of this program was a
maturation modeling project designed to identify oil prone fetch areas. This work played a
significant role in the PL095 award (ConocoPhillips initial operator). The first well in the license
was positioned within the mature oil window but failed due to an expanded Melke Formation
which pushed the main Jurassic reservoir deeper than prognosed. The second well, 6507/7-2, was
positioned in an immature oil window but up-dip from a mature fetch cell. It resulted in the
Heidrun discovery. Significant learnings in terms of porosity preservation and maturationmigration trends followed from this early work. The Heidrun discovery helped spur a
continuation of successful exploration on the Halten Terrace that has carried through to recent
times.
In the mid 1990's the authorities opened portions of the Vring and Mre areas for the 15th
Licensing Round. To prepare for the round, ConocoPhillips conducted an extensive seismicstratigraphic and sequence stratigraphic regional project tying in well data from the Halten
Terrace and West of Shetlands together with outcrop data from East Greenland. Focus at this
time was on the large structural potential offered by the Ormen Lange, Vema and Nyk Domes. In
the Vring Basin, syn-rift Upper Cretaceous to Paleocene reservoir sands were postulated,
sourced from the uplifted pre-drift East Greenland Shelf and mainland Norway. Paleocene sands
were also predicted to be present in the Mre Basin structures. At the time of application it was
thought the Ormen Lange structure would be gas prone due to deep burial of Jurassic source
rocks. The Vema Dome and Nyk High were thought to have better potential for oil, but only if
liquids were preserved by well timed migration episodes. ConocoPhillips was awarded interest in
the Vema Dome (PL215) and later farmed into the Nyk Dome (PL217 & PL218). Subsequent
drilling confirmed that reservoir predictions were largely correct. However, even though
significant quantities of dry gas were found at Ormen Lange and Aasta Hansteen (Nyk), no direct
evidence of a working Jurassic source was proven.
In the early 2000's, additional significant structural potential was made accessible via the 16th
and 17th Licensing Rounds in both the Vring and Mre Basins. Influenced by the Ormen Lange
and Luva gas discoveries with associated direct hydrocarbon indicators, the companys
exploration mandate was expanded to include the search for both large oil and large gas
prospects. Interest in six exploration licenses was obtained during this phase (PL254, PL258,
PL264, PL281 and PL283). PL258 targeted rotated Jurassic fault blocks on the south west flank
of the Gjallar Ridge, with an assumed oil mature Jurassic source. PL264 was centered on the
Nagalfar Dome, directly north from the Luva discovery, where play fairway mapping suggested
Cretaceous sandstones would be present. Modeling studies predicted potential for a liquids
charge from mature Jurassic source rocks interpreted to underlay basaltic sheet flows to the west.
PL254 and PL281 were acquired based on pursuit of giant gas prospects with Upper CretaceousEocene basin floor sand reservoirs draped over large inversion features. These prospects both
demonstrated amplitude conformance. In addition the PL281 prospect had a well developed flat
event. PL283 was also acquired in search of giant gas with a main prospect that targeted a rotated
Cretaceous fault block with a recognized AVO anomaly associated with the Lysing Formation.
All of these licenses except PL258 have been tested with wildcat wells. Significant challenged
resources were found but despite the robust direct hydrocarbon indicators, no commercial
discoveries were made. The principal failure was reservoir quality.
In preparation for the 19th Round, ConocoPhillips embarked on a renewed regional work
program. The primary objective was to evaluate and characterize the basin for liquids potential.
These efforts led to the high grading of postulated Cretaceous and Jurassic oil prone opportunities
along the Gjallar Ridge. On the southern flank of the ridge a prominent Cretaceous four-way dipclosed structure with an underlying large and robust tilted fault block, potentially of Jurassic age,
was identified. It was hoped that this prospect, Dalsnuten, would contain oil sourced from Late
Jurassic shales. The blocks were applied for and interest was secured with a firm well
commitment. In preparation for the 21st License Round, the company conducted proprietary
reprocessing ventures to position for analogous opportunities along the western margins of the
Mre and Vring Basins. An application for the Bach Prospect, situated at the north end of
Gjallar Ridge was submitted. The Dalsnuten Prospect reached total drilling depth after the bid
round was closed. Results demonstrated significant deviation from the pre-drill interpretation in
that the structural development of the underlying fault block was younger than prognosed, the
well failed to prove viable reservoirs and there were no significant shows. Given shared risks
with the Dalsnuten prospect the application for the Bach Prospect was withdrawn.
Although several large gas discoveries have been made in the Vring and Mre Basins, a
westward extent of the prolific Jurassic source rock has not yet been proven. From a gas
perspective, a large proportion of the wildcat tests outboard of the Halten Terrace failed, largely
due to reservoir presence or quality. In recent years industry interest in wildcat exploration in this
area has diminished. In the 22nd License Round, out of 86 blocks announced only 14 were in the
Norwegian Sea. It is hoped that sharing lessons learned from previous drilling may spur
discussions that could help revive exploration in the area. Moreover, it is duly noted that in
addition to the structural and stratigraphic concepts that have been drilled, there is remaining
untested potential beneath the poorly imaged sub-basalt province to the west, as well as within the
currently un-opened acreage of the greater Nordland-Vesterlen area to the north. Combined
industry learnings will help optimize exploration efficiency when pursuing opportunities in these
as yet untested domains.
Permian stratigraphy of the Southern Nordland Ridge, Haltenbanken: Results from recent
exploration drilling
Chris Dart, Anne-Lise Lysholm, Lars Stemmerik* & Stefan Piasecki*
E.ON E&P Norge AS, Norway; *University of Copenhagen, Denmark
Introduction
Following E.ONs acquisition of a 28% stake in the Skarv development, the company placed a
heightened focus on exploration on, and around, the Dnna Terrace. Years of Jurassic and Cretaceous
exploration had all but exhausted the potential for finding significant discoveries in these classic
plays. Therefore, a possibility to test the under-explored Permian carbonate play in a large structure
within the southern Nordland Ridge offered a promising frontier exploration opportunity. Although
the well was dry, valuable new information was collected, confirming that an analogous Permian
carbonate stratigraphy to East Greenland is present on the Norwegian side of the North Atlantic.
Unfortunately, however, the Permian carbonates of mid-Norway still remain one of the great
unconfirmed plays of the NCS.
E.ON acknowledges partners Statoil Petroleum AS and PGNiG Norway AS for active contributions to
the exploration effort, and permission to release information released in this presentation and abstract.
Photo
below
Wegner Halv Fm equivalent was unfortunately developed in a fine grained off-reef distal turbidite
facies, without reservoir potential.
Data from the well are still being analysed, and work continues to identify new ways of approaching
the, as yet unproven, play. Hopefully this new data point is just a milestone on the journey, and not
the conclusion of the mid-Norway Permian carbonate exploration story.
References
Blystad, P., Brekke, H., Frseth, R. B., Larsen, B. T., Skogseid, J., & Trudbakken, B. 1995 Structural
elements of the Norwegian Continental Shelf. Part II: The Norwegian Sea region. Norwegian Petroleum
Directorate Bulletin 8.
Bugge, T., Rings, J. E., Leith, D. A., Mangerud, G., Weiss, H. M. & Leith, T. L. 2002 Upper Permian as a
new play model on the Mid-Norwegian continental shelf: investigated by shallow stratigraphic drilling:
American Association of Petroleum Geologists Bulletin 86, 107-127.
Piasecki, S. & Stemmerik, L. 1991 Late Permian anoxia of central East Greenland. In: Modern and ancient
shelf anoxia, Tyson, R. V. & Pearson, T. H., Eds., Geological Society of London Special Publication 58, 275290.
Stemmerik, L., Scolle, P. A., Henk., F.H., Di Liegro, G. & Ulmer, D. S. 1993 Sedimentology and diagenesis
of the Upper Permian Wegener Halv Formation carbonates along the margins of the Jameson Land Basin, East
Greenland. In: Arctic geology and petroleum potential, Vorren, T.O., Bergsager, E., Dahl-Stamnes, . A.,
Holter, E., Johansen, B., Lie, E. & Lund, T. B., Eds., NPF Special Publication 2, Elsevier, Amsterdam, 107119.
Surlyk, F., Hurst, J. M., Piasecki, S., Rolle, F., Scholle, P. A., Stemmerik, L. & Thomsen, E. 1986 The
Permian of the western margin of the Greenland Sea a future exploration target. In M.T. Halbouty (ed.) Future
petroleum provinces of the world. American Association of Petroleum Geologists Memoir 40, 629659.
the
high
was
obtained
in
Pliocene.
Hydrocarbon
indicators
strongly
suggested
leakage
from
the
west
flank
of
the
Karmsund
Graben
into
the
overlying
Miocene
Utsira
Formation
and
a
subsequent
migration
from
east
to
west
within
this
sequence.
Leads
in
stratigraphic
traps
in
Paleocene
and
Upper
Jurassic/Lower
Cretaceous
sequences
along
the
western
and
south-western
flanks
of
the
Haugaland
High
were
considered
possible.
The
Jurassic/Cretaceous
play
concept
was
enhanced
by
the
Hanz
and
West
Cable
discoveries
and
16/1-3
well.
The
Paleocene
play
was
based
on
the
Verdandi
and
Biotitt
discoveries
and
sand
found
in
several
wells
on
the
west
flank
of
the
high.
The
discovery
of
the
Edvard
Grieg
Field
(16/1-8
drilled
in
2007)
proved
the
play
concept
related
to
filling
of
the
whole
high.
The
Edvard
Grieg
discovery
calibrated
the
migration
concept
and
importantly
converted
the
Johan
Sverdrup
prospect
in
to
a
low
risk
prospect.
Hence
a
firm
well
commitment
was
included
in
the
APA
2009
application.
The
Apollo
prospect
was
drilled
in
2010
by
well
16/1-14
on
a
multi-target
concept
with
the
primary
target
being
the
Hugin
sand
on
lapping
the
Ivar
sen
discovery
and
the
secondary
target
being
the
younger
Upper
Jurassic/Lower
Cretaceous
and
Paleocene.
The
Hugin
sand
was
thinner
than
prognosis
and
found
below
the
Ivar
sen
oil
water
contact.
However,
mildly
biodegraded
oil
was
found
in
Paleocene
sands
and
high
shrinkage
oil
in
a
small
Lower
Cretaceous
accumulation.
The
Edvard
Grieg
discovery
could
easily
have
been
overlooked
without
extensive
data
acquisition;
respectively
coring,
detailed
fluid
sampling
and
well
testing.
The
mineralogical
nature
of
the
sand
matrix
and
abundance
of
conglomeratic
pebbles
made
it
challenging
to
establish
the
petrophysical
properties,
fluid
saturation
and
fluid
contacts
using
electrical
logs.
Understanding
the
petrophysical
properties
of
the
reservoir
has
only
been
achieved
by
detailed
analysis
of
the
cores.
The
oil
leg
in
the
discovery
well
16/1-8
was
established
by
detailed
fluid
sampling
in
a
zone
where
the
UV
light
showed
oil
in
the
cores
with
little
support
from
the
ordinary
E-logs.
The
well
was
temporarily
abandoned
for
testing
at
a
later
date.
The
first
Edvard
Grieg
appraisal
well
(16/1-10)
was
tested
by
perforating
and
producing
the
upper
sand.
The
well
test
revealed
that
the
thin
sand
on
the
top
communicated
with
a
much
better
reservoir
facies
close
to
the
appraisal
well.
The
dynamic
well
test
interpretation
concluded
that
an
approximately
50
m
thick
multi-Darcy
sand
was
required
to
provide
the
observed
pressure
support.
At
the
same
time,
new
OBC
3D
seismic
acquisition
techniques
and
geophysical
methods
unfolded
a
better
picture
of
the
subsurface
indicating
a
thicker
reservoir
west
of
the
first
appraisal
well.
Encouraged
by
the
good
well
test
the
discovery
well
(16/1-8)
was
re-entered
and
tested.
Again
a
strong
pressure
support
was
identified
by
the
dynamic
well
test
interpretation.
The
second
appraisal
well
(16/1-13)
encountered
excellent
45
m
thick
high
permeable
sandstone.
Following
the
Edvard
Grieg
discovery
the
Luno
South
well
(16/1-12)
was
drilled
and
instead
of
proving
sediments
oil
bearing
porous
weathered
basement
was
encountered.
This
discovery
has
a
10m
shallower
OWC
compared
to
Edvard
Grieg.
The
well
16/1-15
was
drilled
to
prove
a
potential
northern
extension
of
the
Edvard
Grieg
discovery.
Oil
was
found
in
Valanginian
age
bioclastic
calcareous
sandstone
resting
directly
on
weathered
basement.
This
discovery
is
in
pressure
communication
with
the
main
reservoir
and
is
included
as
part
of
the
Edvard
Grieg
Field.
The
porous
basement
and
the
bioclactic
sandstone
were
successfully
tested.
This
was
the
first
time
porous
basement
was
tested
on
the
NOCS.
The
Edvard
Grieg
Field
has
6
different
facies
types
that
are
new
to
the
Norwegian
shelf.
The
Edvard
Grieg
discovery
upgraded
the
Johan
Sverdrup
structure
on
the
east
flank
of
the
Haugaland
High
to
a
low
risk
prospect.
The
Johan
Sverdrup
discovery
well
16/2-6
was
located
in
a
position
to
maximise
the
stratigraphic
information
in
the
previously
undrilled
Karmsund
Graben.
The
Johan
Sverdrup
discovery
well
(16/2-6)
encountered
an
oil
column
of
17m.
The
cores
showed
five
meters
Draupne
Formation
shale
and
six
meters
Volgian
age
sand
separated
from
the
Vestland
group
by
a
base
Volgian
regional
unconformity.
The
total
Jurassic
thickness
was
29
m
with
an
OWC
contact
at
1922
m
MSL.
Live
oil
was
found
vugs
in
caliche
below
the
OWC
at
a
depth
of
1940
m
MSL.
The
Volgian
sand
was
tested
and
showed
extremely
good
reservoir
properties
with
lateral
continuity
proven
by
drill
stem
testing.
The
permeability
was
interpreted
to
36000
mD
resulting
in
a
radius
of
investigation
of
3000
to
6000
m.
The
test
was
essential
in
establishing
that
the
recoverable
resources
proven
by
the
first
well
was
in
the
range
of
100
-
400
million
barrels
of
oil.
The
extremely
good
reservoir
properties
and
excellent
lateral
continuity
was
confirmed
by
the
first
appraisal
well
16/3-4
that
was
drilled
between
the
old
down
flank
well
16/3-2
and
the
discovery
well.
The
permeability
was
interpreted
to
35000
mD
with
similar
investigation
radii
as
well
16/2-6.
The
extensive
delineation
program,
including
sidetracks
and
testing,
have
been
essential
for
the
rapid
unfolding
of
the
reservoir.
The
later
delineation
wells
drilled
in
2011
confirmed
the
optimistic
predrill
view
of
a
giant
oil
discovery.
Each
new
well
drilled
in
2012
and
2013
have
given
new
knowledge
and
learning.
The
oil
water
contact
has
been
varying
between
1922
and
1934
m
MSL.
This
must
be
understood
in
the
context
of
recent
migration
and
remigration
response
to
glacial
induced
isostatic
uplift.
The
Edvard
Grieg
discovery
was
covered
by
a
40
km 2
3D
OBC
in
2008.
In
2009
a
1675
km2
3D
Geostreamer
survey
(the
first
on
the
NCS)
was
acquired
over
the
Haugaland
High.
Following
the
Johan
Sverdrup
discovery
2600
km2
Broadsize
3D
was
acquired
in
2010
and
11
(the
first
commercial
survey
on
the
NCS).
These
broadband
seismic
surveys
are
improving
the
imaging
of
the
whole
sequence
from
sea
bottom
into
basement.
The
main
new
elements
in
the
understanding
of
the
petroleum
habitat
of
the
Haugaland
High
are:
Efficient
migration
of
light
oil
into
the
prospects
the
last
1.5
million
years
through
multi-Darcy
Volgian
age
sand
when
the
reservoirs
where
beneath
a
depth
corresponding
to
a
temperature
of
more
than
800
C.
Light
under
saturated
oil
flanking
saturated
oil
and
gas
discovery
due
to
Late
Miocene
pressure
barriers
Late
Miocene
inversion
and
Pleistocene
subsidence
have
significant
influence
on
the
current
structuring
and
migration
and
re-migration.
Glacial
induced
istostasy
has
also
affected
the
re-
migration
New
reservoir
targets
have
been
established
on
the
Haugaland
High:
Continental
proximal
reservoir
rocks
in
the
Edvard
Grieg
discovery.
Porous
producible
basement
rocks
in
the
Luno
South
and
Tellus
discoveries.
Transgressive
marine
Volgian
age
sandstone
with
extremely
good
reservoir
properties
overlying
marine
and
fluvial
Upper
Jurassic
sediment
in
Johan
Sverdrup
discovery.
Lower
Cretaceous/Upper
Jurassic
shelf
sandstone
reservoirs
along
the
west
flank.
Valanginian
age
calcareous
porous
sandstone
in
Tellus.
Porous Zechstein has been observed in 4 wells 16/2-6, 16/2-7, 16/2-16 and 16/3-5
These
new
concepts
have
opened
up
for
an
extensive
exploration
campaign
in
surrounding
licenses
on
the
southern
Utsira
High.
The
following
prospects
will
be
drilled
in
2013:
Additional
leads
are
being
matured
for
drilling
in
the
years
to
come.
Unfolding the complex geology and outline of the giant Johan Sverdrup discovery through
appraisal drilling and subsurface modelling
yvind M. Skjveland, Ane Birgitte Ndtvedt and Tone Ferstad Statoil ASA
Arild Jrstad and Harald Selseng - Lundin Norway AS
The Johan Sverdrup discovery is situated on the east flank of the Utsira Basement High in the North Sea. The
discovery is located in licenses PL265 and PL501. The partners in PL265 are Statoil ASA (op) 40%, Petoro
30%, Det norske oljeselskap ASA 20% and Lundin Norway AS 10%. The partners in PL501 are Lundin
Norway AS (op) 40%, Statoil ASA 40% and Maersk Oil Norway 20%.
Following the results of Det Norskes Draupne discovery (now Ivar Aasen), Lundins Luno discovery (Now
Edvard Grieg) and Statoils Ragnarrock discovery, all drilled in 2007/2008 on the western rim of the Utsira
High and on the high itself, several companies applied for the PL501 license in the 2008 APA round. The well
16/3-2 from 1976 had proven Jurassic sand to be present on the high, and the 2007/2008 discoveries greatly
increased the likelihood of migration to the east of the high from the most likely hydrocarbon source in the
Viking Graben to the west.
Figure
1:
BCU
map
(near
top
reservoir)
with
wells
drilled
to
date
posted.
Wells
16/2-1
to
16/2-5
and
16/3-2
were
drilled
prior
to
the
discovery,
the
other
wells
are
drilled
after
July
2010.
The
main
Utsira
basement
high
area
is
shaded.
The
yellow
line
shows
the
position
of
the
geoseismic
section
of
figure
2.
Figure
2:
Seismic
and
geoseismic
section
through
the
16/2-6
and
16/2-8
wells.
A
black
peak
represents
an
increase
in
acoustic
impedance.
The
envelope
of
the
Jurassic
can
be
interpreted
on
the
seismic
and
is
marked
by
arrows.
Location
of
line
can
be
found
in
figure
1.
The first well to be drilled to test this concept, and thus the discovery well of Johan Sverdrup, was the 16/2-6
well. Following the positive results here, which included a production test (DST) showing excellent reservoir
properties and a laterally extensive upper Jurassic reservoir, this greatly increased the probability of finding oil
in a more westward position, closer to the Utsira high itself.
The 16/2-6 well sits in a location where the Jurassic reservoir thickness is fairly thin (24 meters) and thus
within one seismic cycle. The 16/2-8 well was drilled to test the Jurassic potential further to the west. It was
placed in a position closer to the main boundary fault to the Utsira High - higher on structure and in an
expected thick Jurassic package. The well found a 73 m thick Jurassic reservoir with a net-gross of 0.97,
average porosity of 29% and multi-Darcy permeability. As the pressure data confirmed communication with
the 16/2-6 well, it was now clear that what is now called the Johan Sverdrup field was a large discovery.
The reservoir in Johan Sverdrup consists mostly of late Jurassic-early Cretaceous coarse to very coarse
sandstones (Draupne Fm.) which overlies fluvial to shallow marine Middle Jurassic sandstones that form the
lower part of the reservoir section. The Draupne sandstone consists mostly of gravity flow deposits laid down
along and at the front of fan-deltas directly fed from the basement high and reworked by marine currents.
Marine reworking of the sediments has made the Draupne sandstone nearly mud-free, thus enhancing the
reservoir properties which show porosities in the range of 0.24-0.32 and permeabilities from 1-30 Darcy. The
fluvial to shallow marine Middle Jurassic reservoir (Vestland Gp.) has a more complex facies distribution. New
appraisal wells have revealed varied reservoir properties variations in NTG and sand distribution that are
below seismic resolution. In Late Tithonian age the Karmsund Graben was rapidly drowned, causing
formation of phosphatic-carbonate condensed section that preceded the deposition of deep water hot shales
(Draupne Fm.) in the eastern part of the basin. At the same time, some fine spiculitic sandstones where
deposited into the margins of the Utsira basement high, representing the younger portion of the reservoir.
An extensive appraisal drilling program has been carried out and is still ongoing in both the Statoil-operated
PL265 license and in the Lundin-operated PL501 license. Special focus on data acquisition with extensive
coring, wireline logging and dynamic data has been essential to obtain a better understanding of the reservoir
and how to develop the field. The current plan for production start-up is 2018.
Including the 16/2-6 well with spud in July 2010, 14 wells have been drilled - with an additional 5 sidetracks,
giving in average 50 days between each new data point. This pace will continue in 2013.
This presentation will aim at discussing some of the issues that are addressed with the appraisal wells and
present some results to illustrate this.
One of the major uncertainties in the field relates to depth conversion. As the top of the reservoir is generally
flat, and also since the reservoir envelope is rather thin in some areas, a few meters shift up or down can
move the contact quite a long distance laterally, with implications both for volume and drainage strategy. The
16/5-2 S well serves as an example of this the well came in dry as the overburden velocities were higher
here than predicted by the models.
The contact itself is also uncertain. Most wells show an oil-water contact of around 1921-1925 m TVD MSL,
but the 16/2-10 well proved a contact of 1934m. The recent 16/2-16 well (and sidetrack 16/2-16 A T2) was
drilled with one of the objectives to define contact, and as the deep contact was found only in the sidetrack,
this will help in constraining the area of the deep contact in this area.
The wells drilled so far have confirmed that we seem to have a reasonable good grip on the envelope of the
Jurassic, and as all wells so far have proven a tight Triassic, this is also the envelope of the main reservoir.
Even though the reservoir container is reasonably well understood, the variation of properties within the
container is more difficult to get a grip on, as the seismic not has proven to be of very much help - as wells
with a similar seismic expression have proven quite different reservoir facies.
So far the wells have been placed in a secure distance away from the main fault that defines the western
edge of the graben, to reduce the risk of encountering alluvial conglomerates. The planned 16/2-17 well (Q2
2013) will be drilled in a position close to the fault to investigate this area.
Even though the Triassic rock has proven tight, there could be reservoir potential in deeper strata, such as in
fractured basement proven by the 16/3-4 and 16/2-12 wells, and also in Permian carbonates, which is a
secondary target for the ongoing 16/3-5 well, drilled in a setting where the Triassic is absent.
The field extent to the south and east is controlled by the contact, but towards the north and the west, the
extent is more controlled by the presence or absence of reservoir. The 16/2-9 S well was drilled in 2011 in a
small graben north of the main Johan Sverdrup graben, and encountered spiculite a rock made up of
siliceous sponge spicules that dissolve and can create good secondary porosity but usually very poor
permeability. The very modest reserves in this graben are not considered part of Johan Sverdrup.
Given the disappointing results of the 16/2-9 S well, the results of the 16/2-12 Geitungen well, drilled in 2012
on a basement terrace midway between the spiculites encountered in 16/2-9 S and the Johan Sverdrup field,
was very welcome. This well was regarded as an exploration well with a risk on reservoir presence but
when the well came in with a good reservoir, and only a thin layer of fine spiculitic sandstone at the top, the
well was reclassified as an appraisal well as the pressure data indicated communication with Johan
Sverdrup.
Following up the positive results from Geitungen, it is possible that even more resources may be added to the
Johan Sverdrup volumes this year, both to the north and to the west. An exploration well will be drilled to test
the Torvastad prospect, located to the north of the 16/2-9 S well. Also this year, a well will be drilled to the
west of the main fault in the area west of the 16/2-14 well, to test if sands are present on the basement high
itself. This prospect is called Cliffhanger North.
Block 8/10 is located between the Ula-Gyda Terrace and the Srvestlandet High. The Butch discovery
lies in the Central Trough within a Late Jurassic extensional basin, superimposed on the western flank
of a pre-existing Permo-Triassic basin.
Stratigraphic Setting
The overall trend of the Upper Jurassic Ula Formation is transgressive, passing from shoreface
sandstones into the overlying shelfal siltstones and claystones of the Farsund Formation. However in
detail both progradational and retrogradational cycles are present within the Formation in this area.
Sand deposition in the area is terminated by a significant regional transgressive event, leading to
deposition of hot shales such as Upper Farsund Formation and the Lower Mandal Formation which
acts as both the source rock and seal for the structure, (Figure 4).
Figure 4: Stratigraphic chart across zone of interest. Ula Formation sands present in Butch Main
have been dated as Late Kimmeridgian from biostratigraphic data.
Summary
The King Lear prospect, located in block 2/4 in the Norwegian North Sea, was drilled in 2012 by Statoil on behalf of
PL146 and PL333 (Statoil Petroleum ASA and Total E&P Norge). In July 2012, the partnership confirmed that the highpressure high-temperature (HPHT) 2/4-21 exploration well and subsequent sidetrack appraisal had proven a gas
condensate discovery with estimated recoverable volumes between 70 and 200 million barrels of oil equivalent. This
discovery was made in turbidite sandstones of the Upper Jurassic Farsund Fm. Several wells have previously been
drilled into the Farsund Fm. in the same licence, including the 2/4-14 well in 1988-89, during which a high pressure
reservoir was encountered that ultimately led to an underground blow-out, requiring the drilling of a relief well (2/4-15)
to restore well control. In this paper we present the key objectives and results of 4 exploration wells drilled into the
Farsund Fm., and illustrate how these data led to the evolution of the play concept throughout the exploration history.
The recent integration of pressure, fluid properties, flow rate, petrophysics, geological and geophysical data to further
evaluate conceptual reservoir depositional models, which resulted in the drilling of the 2/4-21 & 2/4-21 A wells is also
presented.
Introduction (or Geological setting / Play context)
The King Lear discovery is located in the Central Graben, approximately 20km north of the Ekofisk Field, and 300km
southwest of Stavanger (Figure 1, left). The discovery lies in a northwest-southeast trending half-graben between the
Hidra High / Steinbit Terrace to the northeast, and the Feda Graben to the southwest. The Farsund Fm. contains turbidite
sandstone reservoirs regionally sourced from the time-equivalent shallow marine platform to the north, encased by the
source rocks of the Haugesund, Farsund and Mandal fms, which also provide a seal to the reservoir (Figure 1, right).
Figure 1: Left: Licence map of PL146, PL333 and surrounding area, highlighting the extent of the King Lear gas
condensate discovery, and locations of key wells. Right: Lithostratigraphic chart, illustrating a simplified play concept
of Farsund Formation turbidite sandstone reservoirs.
Figure 2: South-northeast
oriented sketch geo-seismic
depth-section (based on
2011 seismic data and
interpretations), illustrating
the location of Farsund Fm.
well penetrations in PL146.
Inset map shows the cross
section location (blue line)
and well positions on a
2010 Top Farsund 2
sandstone depth map.
predicted volumes were considered significant and interesting enough to further mature the prospect towards a drillable
candidate.
3) Depositional model:
It should be noted that a material balance approach implies nothing about the location of the container or tank within
which the volumes are reservoired.
Given the relatively thin net sand in the Farsund 2 unit penetrated by 2/4-18R (5m), and unknown thickness in 2/4-14, in
order to contain the volumes calculated from the material balance, the net pay thickness over the structure would need to
be significantly thicker than previously penetrated by the wells.
Coupled with new seismic data and detailed interpretations of the internal stratigraphy of the Farsund Formation, a
model of a potential depocenter with the deepest parts of the half-graben was proposed. This was built on the same belief
before the 2/4-18R well that the reservoir most likely lies in a more proximal setting than the 2/4-14 & 16 wells. This
model accounted for an increase in accommodation space, the palaeotopography of the depositional surface, and
proximity to sand source locations.
2/4-21 King Lear discovery well
By combining the three fundamental concepts referred to above, it was possible to produce an internally consistent
prospect evaluation that tied together all of the data available to mitigate the wide uncertainties present in several of the
analyses. It is this approach that led to the 2/4-21 drill decision. The main objectives of the 2/4-21 well were to prove a
well-developed hydrocarbon bearing reservoir, with pressure data confirming the communication between 2/4-14, 18R &
21.
In 2/4-21, good quality permeable hydrocarbon bearing sandstone was proven on depth and within thickness prognosis at
a depth of over 5000m. Extensive wireline, pressure, core data and fluid samples were acquired. Sidetrack 2/4-21 A was
drilled down-flank approximately 500m to the northwest of the main well to evaluate the variability in reservoir
development and quality and pressure communication, and confirm the deeper extension of the hydrocarbon column. All
of these objectives were met.
Summary/conclusions
Prospect models based on different types of data input: (1) depositional concept; (2) petrophysical analysis and
observations, and (3) material balance model, generated a wide range of prospect analyses. Successful integration of
these different approaches has added to the overall confidence of the resultant prospect volumetrics.
The results of the 2/4-21 & A wells confirmed the model used in the pre-drill evaluations. Good quality reservoir
sandstone, of the prognosed thickness was proven, and in pressure communication with the Farsund 2 sandstones in the
2/4-14 and 2/4-18R wells. These results were achieved without any significant HSE incidents and on schedule in a
HPHT area with a history of well control problems. This is testament to the strong focus on good procedures and solid
knowledge in the planning and operation of the well from Statoil, drilling contractors and partners.
Acknowledgements
The authors acknowledge the PL146 & PL333 partnership (Statoil Petroleum ASA and Total E&P Norge) for permission
to present this paper. The authors also wish to thank the numerous colleagues, partners, and contractors for their
dedicated work during the 25 years of exploration history briefly summarised in this paper.
References
2/4-14 Experience Transfer Seminar, Saga Petroleum, 1991.
Final well reports 2/4-13 & 14, 16, 18R, Saga Petroleum, 1990-1994.
NPD fact pages http://factpages.npd.no
SHELL
E
&
P
Post-rift, deepwater stratigraphic traps, the main theme of this presentation, have proven highly
material where they have a large connected reservoir pore volume and are associated with a rich,
active petroleum system. Significant discoveries of this type include the Marlim, Roncador,
Albacora, and Mexilhao fields from offshore Brazil, the Foinhaven and Schiehallion fields from
the West Shetland Basin, and Ceiba, Jubilee, Tweneboa and Enyenra from offshore West Africa.
Similar subtle traps are also a common success theme in syn- and post-rift stratigraphy of
intracratonic rift basins such as the North Sea and likely occur in other underexplored rift, sag
and post-rift basins globally. In other areas, however, successful traps have proven to be less
than commercial in size. In this contribution, we will look at the trapping styles that are
commonly encountered, the seismic technology used to help identify these, the statistics behind
these discoveries, and from these identify some of the pitfalls awaiting those eager to join the
hunt but for whom geology or serendipity do not favour.
Deepwater Subtle Traps
Two fundamental subtle trap types that recur in deepwater fields with a stratigraphic trapping
component are pinch-out or wedge traps and erosional truncation traps. The former occur
when deepwater sandstones on-lap onto a paleo-slope, while the latter rely upon local or
regional unconformities to create sealing geometries. Between these end-member groups occur
stratigraphic-structural combination traps that represent the bulk of producing traps. Table 1
shows a synthesis of selected trap types determined from published literature and in-house
evaluation. Graphic examples of some of those listed will be shown in the presentation.
Table 1: A selection of DW turbidite traps with a stratigraphic trap component
appetite for deepwater acreage has had an impact on the dynamics of the exploration industry.
There are now many more and smaller players operating within this arena than five years ago
and, as a result, there is little prospective open acreage remaining. But as with all gold rushes,
there will be those who chose wisely and find success, by their own measure, and there will be
those who wont.
Many of the new entrants that have rushed into the African deepwater scene are small to midcap companies that are likely to be under-capitalized for the commitments they have taken on.
Deepwater exploration wells now routinely cost between US$60 150 MM each. There have
also been marked increases in surety-bond liability insurance for deepwater operations
following the Macondo incident. A direct consequence of this high-cost environment is that as
PSCs mature and drilling deadlines approach, equity divestment becomes a necessity. Ioffshore
Africa, deal flow is going though an up cycle that is a direct consequence of the high cost of
deepwater exploration and the difficulty in securing venture capital for drilling operationally
and technically difficult wells. Deal flow opens the back door to more conservative corporations
that have an appetite for relatively low-risk deepwater exploration. However, substantial
financial risks await those who rush into complex deepwater plays without a good
understanding of the technical challenges, especially with promotes on equity running as high as
three-for-one in some deals.
So all of this begs the question, is the West African Cretaceous deepwater turbidite play
currently being hyped by an industry desperate for venture capital, or do the plays warrant
continued high exploration expenditure in the light of recent exploration success? Below, we will
finish this paper with a look at statistics from exploration drilling, field size estimates and
published reservoir data to a plausible answer to this question.
All that is Gold does not Glitter
The graph in Figure 1 shows a creaming curve compiled for the West African Upper Cretaceous
deepwater turbidite play. Of the 62 exploration tests in the population sampled, there have been
47 exploration discoveries (an astounding 76% technical success rate). A success rate such as
this is as much testament to fine exploration acumen as it is to the trapping potential of
deepwater depositional systems. From these there are estimated to be around 17 fields that have
been, are being or have potential to be commercialized under existing fiscal and cost
environments (a 27% commercial success rate). High technical and modest commercial success
spells good news for some as it makes the marketing of undrilled opportunities much easier. It
also makes for an easier sell to management when contemplating a farm-in. But creaming curve
and success statistics can often be misleading. Discovery sizes and reservoir statistics add much
more to the discussion.
Figure 1: West African Upper Cretaceous Deepwater Creaming Curve (data sourced from Wood
Mackenzie, data and other open sources).
A field-size distribution chart created from a global dataset comprising deepwater reservoir
traps that have a stratigraphic trapping component is shown in Figure . Also shown in this chart
is a separation of fields based on reservoir classification. Slope-channel/valley discoveries differ
in size by almost an order of magnitude from discoveries interpreted as confined/unconfined
apron reservoirs.
The post-rift, West African Upper Cretaceous turbidite play of the transform margin basins
comprises sandstones deposited mostly within a slope-channel valley setting. These somewhat
inferior quality reservoirs contrast sharply with the quartz-rich, higher-net-to-gross confined
and/or unconfined toe-of-slope apron systems that are more common in the Paleogene of
offshore Brazil, West-of-Shetland, Mozambique and in the North Sea. Finding modest oil
volumes in poorer quality, often thin channelized reservoirs in tough PSC contract environments
and in deepwater does not make commerciality easy. These observations might explain a
widening gap through time between the technical and commercial success rates across West
African basins as well as the increased pace of deal flow in PSCs in which discoveries have been
made.
Over the next couple of years the rapid pace of exploration drilling will eventually uncover
whether or not the spectacular successes and high resource densities found within the Tano
basin, West Africa and more recently from the Sergipe-Alagoas Basin offshore Brazil, can be
repeated elsewhere along the transform and rift margins on both sides of the Atlantic Basin.
Figure 2 Global field-size distributions compiled from deepwater turbidite discoveries with a
stratigraphic trapping component. The mean field size from the global distribution is 450
MMBOE. The global distribution is separated into two parts based on reservoir depositional
setting: channel/valley and confined/unconfined apron. There is an order of magnitude
difference in mean field size between these, posting mean field sizes of 100 and 930 MMBOE,
respectively.
Marco Orsi1
Eni E&P, Via Emilia 1, 20097 San Donato Milanese (MI), Italy
The huge gas discoveries recently made in Mozambique deep water in both Area 1
(operated by Anadarko) and Area 4 (operated by Eni, with partners ENH, Galp and
Kogas) have clearly shown that the Palaeogene turbidite succession represents the
main exploration target in both areas. In Area 4 these gas-bearing reservoirs have
been indicated with the general term of Mamba Complex. Within the Mamba
Complex each sandstone reservoir package, that can attain thicknesses on the order
of some hundreds of metres, is interpreted to represent a basin floor fan accumulation
(sensu Posamentier and Walker 2006) deposited by sand-rich gravity flows during
lowstands via slope channels and/or canyons originally connected with a shelf area
thought to be located several tens of km westward of Area 4.
With the Miocene, due to the gravitative sliding of the slope, these sediment transfer
conduits and part of the terminal fans were progressively incorporated within the
advancing deformation front of the east-verging toe thrust system. The most
advanced thrust front runs close to the boundary between Area 1 and Area 4. The
Area 4, apart from a gently eastward structural dipping and some NW-SE normal
faults, can be considered as fundamentally undeformed. This relatively simple
structural situation has allowed to reconstruct in detail the external geometry of the
fans enlightening that most of the Oligocene and Eocene systems appear to be
characterized by seismic geometry and lateral facies changes that are unusual in
normal gravity-flow dominated systems: i.e.(1) a marked channel asymmetry with
constant southward shifting of sand depocenters (2)Fan tops constantly showing a
lateral passage from sand to shale responses along gently southward dipping seismic
reflections, (3) local presence of fan-detached sediment waves.
According to the writers previous experience in Atlantic-type deep-water passive
margins (i.e Angola, Nigeria, Gabon), the Mamba Complex reservoir units are
anomalous either in terms of thickness or sand content with respect to the turbidite
systems usually found in these settings. The difference is that the Mamba fans appear
extremely sand-rich, coarse-grained and developed with thicknesses that never have
been directly observed (or described in the literature). In other words, with very few
exceptions, the thick-bedded coarse-grained turbidites that constitute the bulk of the
fan units (Facies F5 sensu Mutti, 1992) are noticeable for the lack of vertically
associated fine-grained facies deposited by the dilute and turbulent part of turbidity
currents (Facies F8 and F9). Where preserved and cored, the finer-grained facies
show strong evidence of transport and deposition affected by the interaction of
turbidite turbulent flow and bottom-current motion: i.e (i) repeated vertical passages,
within the same bed, between parallel lamination and ripples indicating velocity
pulsations; (ii) presence of mud-drapes within the small-scale cross-laminae; (iii) bidirectionality of the cross-laminae within the same bed; (iiii) shale clasts embedded
within fine-grained sand layers. These anomalous structures, combined with the
seismic geometries above described, support the idea of a possible winnowing and
redistribution of the finer materials operated by the action of northward flowing sindepositional bottom currents capable to deflect and incorporate within the adjacent
sediment drifts the fine-grained sediments delivered by the gravity flows.
ABSTRACT
Successful exploration in mature areas; - recipe from Revus and Agora stories
Svein Ilebekk, Cairn Energy UK/Norway
Revus Energy AS was established in late December 2002, financially supported by
HiTec and 3i with a total committed capital of 50 mills USD. The business model was to
organically build an exploration portfolio and to acquire production for tax purposes. The
company was listed on the Oslo Stock Exchange in 2005 and was later taken over by
Wintershall in December 2008. At the start in 2002/2003 the activity on NCS was low,
less than 20 E & P companies were active and only 15-20 exploration and appraisal
wells were drilled each year. The oil price was 20 USD when we started the company.
Agora was formed late 2009, in the middle of the financial crises. As the framework
conditions had changed since we formed Revus and activity level was relative high, the
business model for Agora included exploration drilling on both the UK and Norwegian
continental shelves. The financial support, 200 mills USD, was provided by RIT Capital
Partners plc and Lord Rothschilds family interests. After initial successful exploration
results Agora was taken over by Cairn Energy early 2012.
During the 10 years of activity in Revus and Agora the companies acquired a number of
licences in which there have been a number of discoveries made before and/or after we
were taken over by Wintershall and Cairn. In total the two companies have been
involved in more than 20 discoveries on the UK and Norwegian continental shelves. The
first of these to be put on stream, Knarr (PL373, BG operator), will start production in
2015. The aggregated forward modeled gross and net productions profiles from the
major discoveries indicate 200000-250000 boepd and 60000-80000 boepd respectively
in the period 2016-2024.
How to make such an exploration success? Its a team effort, involving Revus/Agora
teams as well as licence partners and stimulated by the UK and Norwegian authorities.
The key success factors are:
Today the exploration activity level on NCS and UKCS are at peak; - strong competition
for quality acreage, lack of technical resources, cost increase and rig market vacuum for
available slots. Is it possible to duplicate the Revus/Agora story? Yes, it is possible, but
will require the very best technical team available in the market, a focused business
plan and sufficient funding (300-500 mills USD) and a bit of luck.
Ultra Far Offset seismic data valuable info from data formerly regarded as garbage
Alternative source basin giving life to well known structures formerly regarded too
risky
Fig 1. BCU twt map with fields and discoveries (incl. elements from PGS Mega Merge grid)
The PL551 Mantra prospect will be drilled in 2013. Mantra is a 147 mboe oil prospect
supported by a depth consistent seismic anomaly in a rotated Jurassic fault block (Fig.2).
The main reservoir is in the late Jurassic Sognefjord Fm, proven as excellent in the Troll
Field. The main challenge with the Mantra prospect is source and migration, assuming a
main model for sourcing from the marginally mature Heather Fm. at the Uer Terrace.
Alternative models include migration from mature Draupne and Heather Fms. in (1) the Sogn
Graben via the Skarfjell oil discovery and (2) the Lomre Terrace.
Fig. 2. Cross section through licenses PL550 and PL551 demonstrating the relationship between the
northern tip of the Troll Field and the identified prospects and leads.
The 2013 Mantra well will also test the significant Kuro prospect in a down-flank position.
Kuro is a 118 GSm3 Paleocene gas prospect. Seismic and well observations on the eastern
flanks of Troll indicate that Paleocene Ty Fm. sandstones are in direct communication with
the Sognefjord Fm. Troll gas pay. The Ty Fm. sandstones are interpreted to be the source
(parent) of a large scale Paleocene injectite sandstone complex (Fig. 3). Extrapolated Troll
gas pressure gradient intersects the regional minimum fracture gradient at depth of the Kuro
prospect apex. The apex of the Kuro prospect may act as a pressure valve for the entire Troll
Field, and could hold a gas column of 550m in dynamic equilibrium. This hydrodynamic
trap/valve model is supported by pockmarks and significant shallow gas observations in the
overburden above the Kuro apex.
In the late Jurassic syn-rift succession several stratigraphic trap prospects are identified.
Ultra Far offset seismic data have been key in identifying these prospects. The PL550
Gotama prospect is defined by an ultra far offset seismic anomaly very similar to anomalies
matching the Fram and Troll Field outlines. The main reservoir of the Gotama prospect is
intra Draupne Fm. sandstone, believed to be re-deposited Sognefjord Fm. sandstones
eroded off a paleo Troll high.
Tullow Oil Norge holds 5 licenses around the Troll Field, and we believe there is still a
substantial potential for discoveries on the flanks of Troll. Drilling activity the next few years
will prove whether the prospect models are right or wrong. To be continued . (Exploration
Revived 2015?)
Fig 3. The Kuro prospect: Paleocene sand injectite complex in direct communication with the gas pay
of the Troll Field. Extrapolated Troll gas pressure gradient intersects the regional minimum fracture
gradient at depth of the Kuro apex (1000 mSS). The apex of the Kuro prospect may act as a pressure
valve for the entire Troll Field, and could hold a gas column of 550m in dynamic equilibrium. This
hydrodynamic trap/valve model is supported by shallow gas and pockmark observations in overburden
above the Kuro Apex.
Abstract:
Titan appraisal well planned to be drilled late 2013 and to map further exploration potential in
the PL420 license.
Extended
abstract:
The
35/9-7,
Skarfjell
Discovery,
The
Skarfjell
Discovery:
Jens-Ole
Koch,
Sabine
Rssle,
Geert
Strik,
Bernhard
Frey,
Marius
Brundiers
&
Rolf
Magne
Pettersen,
Wintershall
Norge
AS
The
Skarfjell
discovery
was
made
by
the
35/9-7
well
drilled
in
March
to
April
of
2012
in
PL418
in
the
Northern
North
Sea,
17kms
southwest
of
the
Gja
Field.
The
well
found
two
intra
Heather
sandstone
sections
with
light
oil
and
good
reservoir
quality.
The
discovery
is
situated
on
the
Ryggsteinen
Ridge
between
the
Titan
(35/9-6S)
and
Grosbeak
(35/12-2)
discoveries.
A
stratigraphic
trap
is
formed
by
up-dip
truncation
of
the
intra
Heather
sands
by
an
intra
Volgian/Base
Draupne
unconformity
towards
the
SE
and
a
slope
dipping
towards
the
NE.
The
vertical
height
from
the
mapped
crest
of
the
structure
around
2400m
to
the
mapped
potential
spill-point
is
approximately
600m.
The
majority
of
the
trap
is
situated
in
PL418
but
extends
in
to
the
PL378
towards
the
South.
In
the
largest
scenarioes
the
trap
may
extend
into
the
PL420.
The
area
is
covered
by
an
old
3D
seismic
survey
of
relative
poor
quality
and
a
recent
survey
acquired
in
2012.
The
two
intra
Heather
sands
consist
of
high
density
gravity
flow
deposits
and
slope
channel
sandstones
deposited
in
an
offshore
marine
environment.
The
upper
reservoir
section
is
of
Middle
Oxfordian
age
whereas
the
lower
section
is
likely
to
be
Bathonian.
The
gross
and
net
reservoir
thickness
is
69/49m
for
the
upper
sand
and
14/6m
for
the
lower
sand.
The
sands
are
deposited
immediately
northwest
and
west
of
the
time
equivalent
shallow
marine
sandstones
of
the
Sognefjord
and
Krossfjord
Formations
in
the
Gja,
Fram
East
and
Troll
Fields.
Both
intra
Heather
sandstones
were
saturated
with
light
oil
of
good
quality
to
the
base
of
the
reservoirs
in
an
ODT
situation.
The
ODT
was
found
260m
below
the
mapped
crest
of
the
structure
in
the
upper
sand
and
360m
below
the
crest
in
the
lower
sand.
Based
on
the
PVT
data
Skarfjell
may
have
a
gas
cap
updip
of
the
discovery
well.
The
oils
in
the
two
sands
have
slightly
different
density
and
composition
and
fall
on
the
same
pressure
gradient
within
one
bar.
The
Skarfjell
structure
is
cut
by
a
series
of
northwest-southeast
trending
normal
faults
formed
by
extension
during
several
episodes
in
the
Late
Jurassic.
The
faults
are
relatively
short
and
the
reservoir
is
likely
to
be
connected
through
non
faulted
areas
and
across
faults
with
small
throw.
The
faults
are
likely
to
have
been
active
during
deposition
of
the
intra
Heather
sandstones
which
are
generally
thought
to
be
thickening
downdip.
Due
to
the
relative
poor
quality
of
the
seismic
data
and
the
location
of
the
discovery
at,
or
close
to,
the
shallow
marine
to
offshore
depositional
transition,
there
is
a
significant
uncertainty
on
the
reservoir
distribution,
in
addition
to
the
reservoir
thickness
and
quality.
Furthermore
the
depth
of
the
OWC
is
still
unknown
and
the
presence
and
thickness
of
a
gas
cap
is
uncertain.
These
uncertainties
are
the
focus
of
the
appraisal
program
which
consists
of
a
Skarfjell
North
appraisal
well
in
PL418
and
a
Skarfjell
South
appraisal
well
in
PL378.
The
main
objectives
of
the
two
appraisal
wells
and
optional
sidetracks
are
to
find
the
hydrocarbon
contacts
and
to
acquire
3-4
reservoir
penetrations
with
a
full
set
of
reservoir
data
including
a
DST
in
one
of
the
wellbores.
Wintershall
Norge
AS
thanks
the
partners:
Agora
Oil
&
Gas,
Bayerngas
Norge
AS,
Edison
International
Norway
Branch
&
RDE
Dea
Norge
AS
for
permission
to
publish
this
extended
abstract.
P50 GOC
2553 m
TVDSS
Crest at 2394
m TVDSS
General
Spillpoint at
2990 m TVDSS
35/9-7
CPI
showing
very
good
reservoir
quality
of
Intra
Heather
Sandstones
1
&
2.
Arbitrary
seismic
line
from
the
RD1201
3D
seismic
survey
across
the
Skarfjell
Discovery