The 5th Biennial Petroleum Geology Conference
Exploration Revived 2013
Grieghallen, Bergen
18-20 March 2013
Contents
Quick tip: Use this table of contents to navigate. Click an abstract to view its first page.
• The future of NCS exploration – New plays/areas (Key Note) ...4 • Skrugard – a breakthrough in the Barents Sea ...6 • Play types and prospectivity on and around the Loppa High ...10 • Veslemøy High, Barents Sea: Geology and plays ...11 • The Caurus discovery, Barents Sea – A new look at the middle Triassic Kobbe formation ...15 • Petroleum geology of Nordland VI, VII and Troms II ...18 • Finding Arctic oil giants: How to risk Barents Sea uplift and erosion? ...20 • From Heidrun to the Outer Vøring Margin: Lessons learned in search of a westward extension to the prolific Halten Terrace Jurassic oil play ...21 • Permian stratigraphy of the Southern Nordland Ridge, Haltenbanken: Results from recent exploration drilling ...24 • How innovative thinking can lead to exploration success? (Key Note) ...28 • The Edvard Grieg – Johan Sverdrup exploration history and future area potential ...29 • Unfolding the complex geology and outline of the giant Johan Sverdrup discovery through appraisal drilling and subsurface modelling ...33 • The Butch oil discovery ...37 • King Lear: Rewriting the play ...41 • Hunting for subtle traps – Geology to technology ...45 • The Mamba complex supergiant gas discovery: An example of turbidite fans modified by deepwater tractive bottom currents ...50 • Successful exploration in mature areas: Recipe from Revus and Agora stories (Key Note) ...51 • Revived exploration on the flanks of Troll ...52 • The 35/9-6S Titan discovery ...55 • The 35/9-7 Skarfjell discovery ...57
Abstract
Page
Programme committee
• Odd Ragnar Heum, Det norske oljeselskap (chair) • Tim J. Austin, ConocoPhillips Norge
• Tore Berg, Agora Oil
• Kari Berge, A/S Norske Shell • Marcello Cecchi, Wintershall Norge • Frode Fasteland, Statoil
• Kees Jongepier, Svenska Petroleum Exploration • Dag Helland-Hansen, Tellus Petroleum
• Jorun M. Ormøy, Eni Norge
• Jan Strømmen, Maersk Oil Norway
• Wenche Tjelta Johansen, Norwegian Petroleum Directorate • Viggo Tjensvoll, Centrica Energi
The future of NCS exploration – New plays/areas
Sissel Eriksen, Norwegian Petroleum Directorate (NPD)
Abstract:
The NPD has revised its resource estimates and quantified the total expected undiscovered
recoverable resources at 2590 million standard cubic metres (Sm
3) of oil equivalents (o.e.).
The table below shows the numbers and uncertainty range.
P90 Expected P10
mill/bill Sm
3mill/bill Sm
3mill/bill Sm
3Liquid
630
1400
2450
Gas
525
1190
2100
Total
1290
2590
4400
The previous estimate from 2010 was 20 million Sm
3o.e.
lower. Approximately 270 million
Sm
3o.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.
The seismic data that has been acquired off the coast of Helgeland is a part of the
government’s “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
Björn 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 1980’s; 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 1990’s, 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 Bjørnøya Basin/Bjørnøyrenna 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 Stø 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 Stø, Nordmela and Tubåen 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 (DHI’s), 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. DHI’s 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 Bjørnøya 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 Stø depth map, showing the location of the Skrugard and Havis discoveries within the Bjørnøyrenna Fault Zone on the western flank of the Barents Sea. Structural elements from Norwegian Petroleum Directorate.
Fig. 2: Semi-regional map of Top Stø 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., Kjøsnes, Ø., 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,
“Play types and prospectivity on
and around the Loppa High”
Harald Brunstad,Trond Kristensen and Espen T.
Ulvesæter
Lundin Norway AS
Abstract:
Lundin Norway has actively explored the area on and around the
Loppa High since the award of Lundin’s 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 Norway’s perspective.
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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 Snøtinden 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).
Objectives and challenges
The key challenges and key risks on Caurus are believed to be related to reservoir quality and trap geometry. Grain size comprises the primary control on the reservoir properties and for commercial production coarser than very fine grained sandstone is necessary. The trap geometry is still not fully understood and the real trap could be a much more limited stratigraphic /structural trap than the hitherto mapped closure.
It is believed that well 7222/11-‐1 on Caurus, alongside with all other wells drilled in the Bjarmeland area, is not optimally placed to test the Kobbe Formation. The license group has been working towards an optimal placement for the second exploration well on Caurus, where the main objective is to target and test one of the main channelized sandstones visible from seismic analysis. The aim is to prove better reservoir properties, prove commercial production rates (by DST) and to evaluate HC-‐contacts. We also hope the planned well will give valid information about the trapping mechanism in the Kobbe formation, and a better overall understanding of the complex palaeo-‐ depositional environments in the Bjarmeland area.
Petroleum geology of Nordland VI, VII and Troms II
Ketil Kaada, Norwegian Petroleum Directorate (NPD)
Abstract:
Kjetil Kaada, Norwegian Petroleum Directorate, P. O. Box 600, 4003 Stavanger, Norway
The offshore areas off Nordland and Troms are regarded by the petroleum industry as one of the most attractive new areas for petroleum exploration. Due to environmental and fishery concerns, only parts of this area have so far been open for exploration. Since 2001, the whole area has been closed.
As part of the management plan for the Barents Sea and the sea areas off the Lofoten Islands it was decided in 2006 to acquire more information, investigating all relevant issues. The Norwegian Petroleum Directorate has, as a part of this plan, conducted an independent evaluation of the petroleum geology and petroleum resource potential of these areas.
The offshore area close to the Lofoten Islands has a varied and interesting geology. The continental shelf is here at its narrowest, in some places narrower than 20 kilometers. From the outer edge of the continental shelf, the seabed plunges down to abyssal depths greater than 2,500 meters below sea level.
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
70° 72° 74° 68° 66° 66° 68° OD 1302005 Narvik Harstad Bodø Tromsø TROMS II NORDLAND VII NORDLAND VI 15° 10° 5° 0° 20° 15° 20° 25° 10° 5° Location Map
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.
Petroleum geology of Nordland VI, VII and Troms II
Ketil Kaada, Norwegian Petroleum Directorate (NPD)
Abstract:
Kjetil Kaada, Norwegian Petroleum Directorate, P. O. Box 600, 4003 Stavanger, Norway
The offshore areas off Nordland and Troms are regarded by the petroleum industry as one of the most attractive new areas for petroleum exploration. Due to environmental and fishery concerns, only parts of this area have so far been open for exploration. Since 2001, the whole area has been closed.
As part of the management plan for the Barents Sea and the sea areas off the Lofoten Islands it was decided in 2006 to acquire more information, investigating all relevant issues. The Norwegian Petroleum Directorate has, as a part of this plan, conducted an independent evaluation of the petroleum geology and petroleum resource potential of these areas.
The offshore area close to the Lofoten Islands has a varied and interesting geology. The continental shelf is here at its narrowest, in some places narrower than 20 kilometers. From the outer edge of the continental shelf, the seabed plunges down to abyssal depths greater than 2,500 meters below sea level.
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
Title: Finding Arctic Oil Giants: How to risk Barents Sea uplift and erosion ?
Authors:
Maersk Oil New Ventures Exploration Team, Stavanger, Norway
Presenter:
Paul Henry Nadeau, Maersk Oil Norway AS, Norway
Abstract: Exploration challenges in sedimentary basins which have undergone significant
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
failure. These challenges, particularly along the structurally complex Barents Sea margin
(Figure 1) require that both the magnitude as well as the timing of U&E events in the
burial/thermal history be accurately estimated and integrated into petroleum systems
considerations. Such analyses often show that trap preservation with respect to hydrocarbon
charge becomes a major risk factor. Geological models for oil and gas entrapment
demonstrate that the vast majority of reserves occur in relatively narrow depth intervals,
mainly determined by the geothermal gradient and maximum reservoir temperature (Bjørkum
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.
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,
and preservation.
References:
Bjørkum, P.A. & P. H. Nadeau, 1998, Temperature controlled porosity/permeability reduction, fluid migration, and petroleum exploration in sedimentary basins. Australian Pet. Prod. & Expl. Assoc.
Journal, 38, 453-464.
Nadeau, P.H., 2011, Earth's energy "Golden Zone": A synthesis from mineralogical research. Clay Minerals, 46, 1-24.
Nadeau, P.H., Bjørkum, P.A. & Walderhaug, O., 2005. Petroleum system analysis: Impact of shale diagenesis on reservoir fluid pressure, hydrocarbon migration and biodegradation risks. In: Doré, A. G. & Vining, B. (eds) Petroleum Geology: North-West Europe and Global Perspectives – Proceedings
of the 6th Petroleum Geology Conference, 1267-1274. Petroleum Geology Conferences Ltd., Published by the Geological Society, London.
Title: Finding Arctic Oil Giants: How to risk Barents Sea uplift and erosion ?
Authors:
Maersk Oil New Ventures Exploration Team, Stavanger, Norway
Presenter:
Paul Henry Nadeau, Maersk Oil Norway AS, Norway
Abstract: Exploration challenges in sedimentary basins which have undergone significant
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
failure. These challenges, particularly along the structurally complex Barents Sea margin
(Figure 1) require that both the magnitude as well as the timing of U&E events in the
burial/thermal history be accurately estimated and integrated into petroleum systems
considerations. Such analyses often show that trap preservation with respect to hydrocarbon
charge becomes a major risk factor. Geological models for oil and gas entrapment
demonstrate that the vast majority of reserves occur in relatively narrow depth intervals,
mainly determined by the geothermal gradient and maximum reservoir temperature (Bjørkum
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.
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,
and preservation.
References:
Bjørkum, P.A. & P. H. Nadeau, 1998, Temperature controlled porosity/permeability reduction, fluid migration, and petroleum exploration in sedimentary basins. Australian Pet. Prod. & Expl. Assoc.
Journal, 38, 453-464.
Nadeau, P.H., 2011, Earth's energy "Golden Zone": A synthesis from mineralogical research. Clay Minerals, 46, 1-24.
Nadeau, P.H., Bjørkum, P.A. & Walderhaug, O., 2005. Petroleum system analysis: Impact of shale diagenesis on reservoir fluid pressure, hydrocarbon migration and biodegradation risks. In: Doré, A. G. & Vining, B. (eds) Petroleum Geology: North-West Europe and Global Perspectives – Proceedings
of the 6th Petroleum Geology Conference, 1267-1274. Petroleum Geology Conferences Ltd., Published by the Geological Society, London.
Figure 1. Structural geo-seismic section along the Western Barents Sea Margin (J. K.
Hansen, pers. com.)
From Heidrun to the Outer Vøring Margin: Lessons learned in search of a
westward extension to the prolific Halten Terrace Jurassic oil play
Roy Leadholm, Tim Austin, Colin Hirning, Rune Mogensen, Chris Parry
Over the last three decades ConocoPhillips has established a legacy of knowledge in Mid Norway through its exploration endeavors and commitment to test multiple play concepts. This activity involved participation in 26 exploration licenses and the drilling of 34 wildcat wells in the Halten Terrace, the Vøring Basin and the Møre Basin (Figure 1).
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. Midgård
(later part of Åsgard 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 maturation-migration 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 Vøring and Møre areas for the 15th Licensing Round. To prepare for the round, ConocoPhillips conducted an extensive seismic-stratigraphic and sequence seismic-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 Vøring 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 Møre 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 Vøring and Møre Basins. Influenced by the Ormen Lange and Luva gas discoveries with associated direct hydrocarbon indicators, the company’s
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 Cretaceous-Eocene 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 dip-closed 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 Møre and Vøring 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 Vøring and Møre 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-Vesterålen 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.ON’s acquisition of a 28% stake in the Skarv development, the company placed a heightened focus on exploration on, and around, the Dønna 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.
Permian stratigraphy of East Greenland
Mapping campaigns from the Geological Survey of Denmark and Greenland (GEUS) and exploration efforts by ARCO in the 1980’s led to the publication of a series of key articles on the Permian
geology of East Greenland in the late 1980’s and early 1990’s (Surlyk et al. 1986; Piasecki & Stemmerik 1991; Stemmerik et al.1993; Stemmerik et al., 1993).
In East Greenland, the Permian sequence sits unconformably on Devonian/Carboniferous coarse clastics, and is overlain by the fine grained sediments of the Triassic Wordie Creek Fm. In Jameson Land, Permian karstified bryozoan carbonate build-ups of the Wegener Halvø Fm. provide potential reservoir rocks that are directly overlain by organic rich shales of the Ravnefjeld Fm. The build-ups are capped and flanked by ooidal and bioclastic packstones and grainstones, further enhancing
reservoir potential. These formations overlie potential secondary reservoirs in the karstified brecciated carbonates of the Karstryggen Fm., and basal conglomerates of the Huledal Fm., completing the exposed East Greenland Permian stratigraphy.
Photo below
Previous drilling results from Haltenbanken
On the Norwegian side of the Atlantic Permian carbonates were first proved in 1983 by the Phillips 6609/7-1 well that penetrated a 36 m remnant of Permian carbonates and sandstones sandwiched between the BCU and crystalline basement rocks. Interest in the mid-Norway Permian play was then
heightened following IKU shallow drilling close to the Norwegian mainland in the 1990’s. Here a
clastic sequence was penetrated spanning the Permian-Triassic boundary and including a potential source rock and hydrocarbon shows. The source rock was later correlated to the Ravnefjeld Fm. by Bugge et al.’s (2002) article, that first synthesised the petroleum potential of the mid Norway Permian play.
Recent exploration drilling results from the Nordland Ridge
PL350 was awarded in APA2004 to a Statoil operated partnership, where E.ON held a minority share. Initial focus on Jurassic prospectivity failed to yield a drillable target, and attention shifted to a large, deep, fault block that occupied most of the southern part of block 6507/6. This structure was not new,
and had already been identified by NPD’s Blystad et al.’s (1995) Bulletin No.8, on the structural
elements of the Norwegian Sea as the Sør High. The deepest well on the block TD’ed several hundred
meters above the reflector that defined the structure. Regional well tie work, however, indicated that this could potentially mark the top of the Permian carbonates.
Statoil organised a license field expedition in the summer of 2008 led by the University of
Copenhagen to study the exposed Permian geology in East Greenland, and much useful information was gathered on likely reservoir parameters.
In 2009 E.ON took over operatorship of PL350, Statoil reduced their share and PGNiG joined the partnership, bringing with them their experience from exploring the Permian carbonate play in Poland. Following the EO09M02 PSDM reprocessing of the available 3D seismic data, a drill decision based on the Permian Sesam prospect was made, with the Triassic Grey Beds Sindbad prospect as a secondary target. PL350B was secured as protection acreage for the northernmost part of the prospect in APA2011.
6507/6-4 was spudded in October 2011, and completed in January 2012. After a long hard Triassic section, the well finally penetrated a complete succession of the Permian stratigraphy and TD’ed in (probable) Carboniferous conglomerates at 4360 m TVDSS. 27 m of core were recovered from the uppermost part of the carbonates. Litho- and biostratigrahic correlation show that all the Permian formations exposed in East Greenland are probably also represented in the 6507/6-4 well. The cored
Wegner Halvø 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., Færseth, R. B., Larsen, B. T., Skogseid, J., & Tørudbakken, B. 1995 Structural
elements of the Norwegian Continental Shelf. Part II: The Norwegian Sea region. Norwegian Petroleum
Directorate Bulletin 8.
Bugge, T., Ringås, 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, 275-290.
Stemmerik, L., Scolle, P. A., Henk., F.H., Di Liegro, G. & Ulmer, D. S. 1993 Sedimentology and diagenesis
of the Upper Permian Wegener Halvø 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, Ø. A., Holter, E., Johansen, B., Lie, E. & Lund, T. B., Eds., NPF Special Publication 2, Elsevier, Amsterdam, 107-119.
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
How innovative thinking can lead to exploration success Angus McCoss, Exploration Director, Tullow Oil plc
Angus McCoss was appointed to the Board of Tullow Oil plc in December 2006. Angus is a geologist with a BP sponsored PhD. Before joining Tullow, Angus had 21 years of wide-‐ranging exploration experience, working primarily with Shell in Africa, Europe, China, South America and the Middle East. He held a number of senior positions within Shell including Americas Regional Vice President Exploration and General Manager of Exploration in Nigeria. He is also a non-‐executive Director of Ikon Science Limited and a member of the Advisory Board of the industry-‐backed Energy and Geoscience Institute of the University of Utah.
Tullow is Africa’s leading oil and gas company and one of the world’s leading exploration companies. Over the past 7 years, the company has made key basin-‐opening discoveries offshore Ghana and in Uganda and Kenya. Tullow now works in 15 countries in Africa and has plans in 2013 to drill high-‐ impact wells in Kenya, Ethiopia, Mozambique, Mauritania and Cote d’Ivoire. Alongside this African success, Tullow has taken its success offshore West Africa over to South America where, in September 2011, the company made the Zaedyus-‐1 discovery, offshore French Guiana. This discovery has lead Tullow to investigate the Atlantic margins further and in 2012 Tullow made five new country entries of which four (Norway, Greenland, Guinea and Uruguay) have Atlantic prospects. This interest in the Atlantic Margins was increased in late 2012 when Tullow acquired Norway’s Spring Energy and was further increased by Spring’s success in the 2012 Norwegian APA Licence Round. In 2013, Tullow Norge (of which Spring is the key constituent) has interests in at least 10 wells, offshore Norway.
In his presentation to Norsk Petroleumsforening, Dr. McCoss will discuss Tullow’s geological and geophysical approach to exploration and he will demonstrate how Tullow’s new interests in Norway fit with the company’s global exploration strategy.
Tullow and Spring are highly complementary to each other. Both companies have a strong record of both discovering and commercialising oil resources and both companies have a strong entrepreneurial streak. Spring has now been integrated into Tullow and Spring’s CEO, Roar Tessum, has been appointed to lead Tullow’s North Atlantic Business Unit which includes acreage offshore Greenland that Tullow farmed-‐in to last year.
Acquiring Spring has complemented Tullow’s expertise in geoscience. Of Spring’s 37 employees, 24 are geologists or geophysicists. Tullow’s abilities in these fields are well recognised and are at the heart of the Company’s major exploration successes since 2006. Tullow’s office in Dublin, where the company was founded, is a centre of geoscientific excellence with close links to University College, Dublin. Tullow’s exploration teams in London and Cape Town are equally capable and form a world-‐ wide exploration effort that is industry-‐leading. This position has been earned through the rigorous application of geoscience and petroleum engineering in analysing potential petroleum systems and sedimentary basins. The geoscientific expertise that Spring has brought to Tullow will not only be vital in evaluating new acreage awarded offshore Norway but in examining analogues throughout the Atlantic Margins.
The Edvard Grieg-‐Johan Sverdrup exploration history and future
area potential
Hans Rønnevik, Arild Jørstad and Daniel Stoddart Lundin
Norway ASSivert Jørgenvåg Statoil ASA
The first exploration drilling campaign in Norway in the late 60’s included the southern Viking Trough and the Utsira High. This campaign resulted in several significant gas and biodegraded oil discoveries related to Jurassic and Paleocene play types (Frigg and Balder fields). The first well on the southern part of the Utsira High, Esso 16/2-‐1 drilled in 1967, had good oil shows in the Tor Formation and basement. This was later referred to as the Ragnarrock discovery and delineated by Statoil in 2007 with the drilling of wells 16/2-‐3 and 4. The delineation drilling concluded that the chalk and basement reservoirs in this area had limited commercial potential.
The initial exploration phase of the area was based on 2D seismic data and the general view in the late 1980's was that the southern Viking Trough and Utsira High was an area of gas or heavy oil. This view hindered the possibility of alternate play types. However the introduction of 3D seismic as an exploration tool in the 1990's opened for more efficient seismic guided exploration that resulted in the discovery of light oil (ie. Jotun, Ringhorne). Further development of the 3D seismic into multi-‐ cube 3D seismic and rock physics analysis integrated with an increase in the diversity of the
geochemical and geological data triggered a new successful exploration effort from 2000. The early success was focused on the Paleocene oil discoveries leading to the Alvheim, Volund and Vilje discoveries.
The southern part of the Utsira High is a basement high that has a kinematic history different from the central and northern part and is hence referred to as Haugaland High. The high is affected by all the major tectonic events from Late Paleozoic to Late Neogene and Pleistocene glacial episodes. These events are all essential for the petroleum habitat of the high.
The prolific petroleum nature of the Haugaland High area was demonstrated by the following oil discoveries: Edvard Grieg (16/1-‐8) in 2007, Draupne (16/1-‐9) in 2008, Luno South (16/1-‐12) in 2009, Apollo discoveries (16/1-‐14) in 2010, the giant Johan Sverdrup discovery (16/2-‐6) in 2010 and the Tellus discovery in 2011 (16/1-‐15). These discoveries are flanking and are pressure sealed off from the saturated light oil/biodegraded black oil 16/2-‐5 discovery at the crest of the high drilled in 2009. In addition the Verdandi gas discovery (16/1-‐6S) was made in 2003.
The initial play concepts developed for the APA 2004 and 2005 license applications highlighted the presence of a 40-‐50 m saturated oil leg in thin Jurassic age sand and inlier basin sediments with a common oil leg flanking the whole Haugaland High. The presence of Upper Jurassic sand play
concept was supported by wells 16/1-‐5 and 16/3-‐2 which showed excellent reservoir properties. The saturated oil leg concept was based on the presence of good oil shows in well 16/1-‐5 and gas in granite was in 16/1-‐4 .
The concept of filling the whole high was supported by an updated macro-‐scale migration model that combined late migration into the Haugaland High from source rock areas in the Viking Trough. This was backed by Tertiary paleo-‐reconstruction of the high that indicated that the current outline of