Expanded Abstracts - Exploration Revived 2013

The 5th Biennial Petroleum Geology Conference

Exploration Revived 2013 Grieghallen, Bergen 18-20 March 2013

www.npf.no

Contents

Abstract

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 • F  rom 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 • U  nfolding 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 • T  he 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

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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 • Håkon Østhus, Core Energy

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 (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 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.  

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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

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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.

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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, EAGE, Expanded Abstract.

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“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.  

 

Example  of  Triassic    channels  

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Vesllemøy High, H Barrents Sea a: Geology and P Plays Janne Guttormseen, Noemí T Tur, Micheele Comisso o, Pieter Peestman Repsol R Explloration No orge AS, Osslo Introoduction The V Veslemøy High H is locateed in the weesternmost portion p of thee Barents Seea, in-betweeen the Trom msø Basin to the SE, and d the Sørvesttsnaget and Bjørnøya 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 Veslemøy 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 Veeslemøy 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 Veslemøy V H High. Untill now, the Veslemøy 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 Veslemøy V High is considdered to be an “antiform shaped by thhe BTU”, theere are t “Veslemøy 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.

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   

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 “Vesllemøy 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 Veslemøy y High is oveerlying a pree-Jurassic bassement high..

Figurre 2. W-E seeismic line through the Veeslemøy High h, indicating g (circled) thee Cretaceouss play below the Baase Tertiary Unconformiity (BTU), an nd the Paleoccene play aboove the BTU U. Strattigraphy The ssedimentary succession of o the Barennts Sea is Palleozoic to Quaternary inn age. Howev ver, in the arrea of the Veslemøy Hig gh, the pre-C Cretaceous su uccession is very deep, aand the interrval of intereest is assumeed to be Cretaaceous to Teertiary in agee (Figure 4). Becauuse of the uncertain u correlation betw ween the refference wellss and the Veeslemøy areaa, it is not ppossible to determine d with certaintyy the age off the sedimen ntary successsion immed diately underrlying the BT TU. Howeveer, the packaage is most liikely Cretaceeous in age: Aptian-Albiian, or Uppeer Cretaceouss. Based on the t seismic iimaging and d data from nearby n wells,, the Cretaceeous is

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expeccted to be shhale-dominatted, with subbordinate saandy intervalls. The Cretaaceous sandsstones are exxpected to bee turbiditic, as a they are allong the Lop ppa High and d in Mid-Norrway. The B BTU is overrlain by the Paleocene-O P Oligocene To orsk Formation, that conssists of claystonedominated clasticcs with subo ordinate sanddstones. Theese sandstonees have beenn drilled in a few wellss (7216/11-11 S and 731 16/5-1), wheere they werre found to be turbiditiic, with exccellent reservvoir quality in some plaaces. Over thhe Veslemøy y High, the lower l part off the Paleocene is absennt, due to onllap onto the paleo-high p (F Figure 2). The uupper Pliocenne-Quaternarry, periglaciaal Nordland Group caps the t sedimenttary successiion.

Figure F 3. Map ap of Base Teertiary (BTU) U). m Playss and Petrolleum System Two plays have been b identifieed on the Ve slemøy 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 D’s 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 NPD’s 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 Vesllemøy 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 Veslemøy 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.

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 Prreservation. Some leakag ge along fauults has occu urred as indiccated by gass clouds visib ble on seeismic. Figurre 4. Stratiigraphy of the Norw wegian B Barents Sea, S show wing reservoiirs and sourrce rockss relevant for the Veslem møy High (based on Worsley 20 008 and L Larssen et all 2005). win Prospectt Darw An exxploratory well, w 7218/11 1-1, will bbe drilled onn the Veslem møy High: on the Daarwin prospeect, locateed in thee southeasteern the portioon. Here, both Paleoozoic and Crretaceous plaays are ppresent and can be tested with one well. The T exploratiion well is scheduledd to be spudd ded in Febbruary 2013. The ttrap of the Darwin D prosp pect is stratigraphic with w a structu ural compponent (Figurre 5). The eexpected reservoirs are two sandsstone intervaals: one at the base of the Paleoccene, the oth her near the toop of the Creetaceous succession.

Figure 5. W-E seismicc line throughh the Darwin n prospect, in ndicating weell position. Ackn nowledgemeents The aauthors thankk the partnerrs in licensee PL531 (Con ncedo ASA, Det norske oljeselskap ASA, Faroee Petroleum Norge AS, Marathon O Oil Norge AS, A RWE Dea D Norge A AS, and Tallisman Energgy Norge AS S) for permisssion to preseent this paperr.

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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.  

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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  

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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.   Det  norske  would  like  to  acknowledge  the  partners  for  constructive  contribution  to  the  license  work.  

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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.   74°

72°

70°

68°

66°

20°

25° Tromsø

15° TROMS II

Hars t ad

20°

Nar vik

Bodø NORDLAND VII

10°

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NORDLAND VI

  5°

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

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                                                                                       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.  

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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 (Bjørkum mainly determined the 2005; geothermal gradient maximum temperature and Nadeau, 1998; Nadeau by et al., Nadeau, 2011).and Applying this reservoir methodology to the (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. 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: Bjørkum, P.A. & P. H. Nadeau, 1998, Temperature controlled porosity/permeability reduction, fluid Bjørkum, 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., Bjørkum, P.A. & Walderhaug, O., 2005. Petroleum system analysis: Impact of shale Nadeau, P.H., Bjørkum, P.A. & Walderhaug, O., 2005. Petroleum systemrisks. analysis: Impact diagenesis on reservoir fluid pressure, hydrocarbon migration and biodegradation In: Doré, A.of shale diagenesis on Petroleum reservoir fluid pressure, hydrocarbon migration and biodegradation risks. In: Doré, 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.)

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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

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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 Vøring and Møre 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 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 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

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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.

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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.

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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).

Photo below

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.

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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

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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, 275290. 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, 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, 629–659.

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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.      

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The  Edvard  Grieg-­‐Johan  Sverdrup  exploration  history  and  future   area  potential   Hans  Rønnevik,  Arild  Jørstad  and  Daniel  Stoddart  Lundin  Norway  AS   Sivert  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  

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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  Åsen  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  Åsen  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  

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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.  

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•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:   • • • • • •

The  Luno  II  prospect  on  the  south  flank  of  the  Haugaland  High     The  Jorvik  prospect  in  between  the  16/2-­‐5  and  Edvard  Grieg  Field   The  Torvestad  prospect   The  Kopervik    Volgian  pinchout  play   The  Biotitt  4  dip  Jurassic  prospect   The  Cliffhanger  prospect    

Additional  leads  are  being  matured  for  drilling  in  the  years  to  come.          

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Unfolding the complex geology and outline of the giant Johan Sverdrup discovery through appraisal drilling and subsurface modelling Øyvind M. Skjæveland, Ane Birgitte Nødtvedt and Tone Ferstad – Statoil ASA Arild Jørstad 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 Norske’s Draupne discovery (now Ivar Aasen), Lundin’s Luno discovery (Now Edvard Grieg) and Statoil’s 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.

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  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.  

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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.

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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.

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The Butch Oil Discovery Jessica Hill Centrica Energi, Norway Introduction Licences PL405 and PL405B covering parts of blocks 8/10 and 7/12 are located along the Northern margin of the oil rich North Sea Central Graben. Centrica Resources Norge AS (Centrica Energi) drilled the exploration well 8/10-4S (as licence operator) on the Butch Main prospect which lies 8km southeast of the producing Ula Field, and approximately 15km north of the Gyda Field, (Figure 1). The licence partnership is comprised of Faroe Petroleum, Tullow Oil and Suncor Energy. The licence was awarded in the APA 2006 licencing round.

Figure 1: Butch Main location map The exploration well 8/10-4S was drilled on a salt induced four way dip closure to evaluate the hydrocarbon bearing potential of the Upper Jurassic Ula sands sealed by the overlying Mandal shales. The expected hydrocarbon phase was light oil due to the close proximity to the nearby Ula field and the assumption that the structure may share the same source. Figure 2 gives an overview of the structure, well placement and proximity of the Butch prospect in relation to the Ula Field. The main pre-drill risk was identified as reservoir presence/quality and seal breach. Structural Setting The Butch Main structure was formed as a result of salt movement in the Late Cretaceous and Palaeocene. The salt movement in this area was largely post depositional and intruded into the overlying Late Jurassic sediments creating a four way dip closed structure around the diaper, which has then been further segmented by faulting related to the salt movement. The faulting appears to define three main segments, one of which is Butch Main, as shown in Figure 3.

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Figure 2: Geo-seismic cross section through the Butch area

Figure 3: Map showing Butch Main structure

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Block 8/10 is located between the Ula-Gyda Terrace and the Sørvestlandet 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.

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Well Results Summary The 8/10-4S well was spudded on 15th August 2011 and after four sidetracks was permanently plugged and abandoned on 15th January 2012 as a light oil discovery. The well was drilled in shallow water depths of 44m and reached a total depth of 3071m MD RKB, 13m into Upper Permian Zechstein anhydrites. Well 8/10-4S only encountered an ODT, a further two sidetracks were drilled to locate the water leg within the Butch Main segment. Two additional sidetracks were then attempted to evaluate the neighbouring Butch Southwest segment (Figure 3), however due to wellbore stability issues both sidetracks did not extend further than the Hordaland Formation. An extensive data program was carried out across the Ula Formation reservoir in both the main wellbore and sidetracks within the Butch Main segment. Approximately 50m of net pay was encountered, and an oil water contact was confirmed using RDT pressure data. The reservoir quality observed from core was exceptional and on trend with that observed in the neighbouring Ula Field. Post drill recoverable volumes are estimated to be in the range of 30-60 million barrels of oil equivalent. Way Forward The Butch Main discovery is currently progressing through the Centrica Energi internal decision gate process. The Mærsk Giant has been secured to drill two exploration wells in the neighbouring Butch East and Butch Southwest segments towards the end of 2013. Acknowledgements Centrica Energi would like to thank the PL405 Partners for their valued input to the licence.

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King Lear: Rewriting the play P. A. Jones1, J. P. Wonham2, D. Sharp1, S. Nordfjord1, M. Ekroll1, J. E. Haugen1. 1

Statoil Petroleum ASA, 2Total E&P Norge.

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.

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Exploration history: 1988 - 1994 The following section presents a brief overview of the drilling operations in PL146, with a focus on the geological information acquired, and input to evolution of play concepts and prospectivity of the Farsund Fm. PL146 was awarded in 1988 to a partnership consisting of, at that time, operator Saga Petroleum ASA, and partners Den norske stats oljeselskap a.s., Elf Petroleum Norge AS, and Amerada Hess Norge AS. 2/4-14: In October 1988, well 2/4-14 was spudded on the ‘A prospect’ in the middle of the northwest-southeast trending structure described as a “structural/stratigraphic closure on a rotated fault block developed during the Upper Jurassic” (Final well report 2/4-13 & 14, 1990), see Figure 2 for the well location relative to current interpretations. The objective of the well was to evaluate the reservoir potential of the expected Upper Jurassic sandstones, and to TD 150m into the Triassic. In January 1989 the well encountered an Upper Jurassic sandstone reservoir at high pressure resulting in a kick (Saga Petroleum, 1991). A cement plug was set, with the intention of drilling a sidetrack to fulfill the well objectives. During preparations for sidetracking on 20th January 1989, the cement plug failed, and the well started flowing. The BOP was closed and the drill pipe cut. During June 1989, 2/4-14 was re-entered with the intention of ‘killing’ the well. On re-connection, unexpectedly ‘low’ pressure readings were encountered in the wellbore – subsequent PLT (Production Logging Tool) and ‘noise’ logs indicated the reservoir fluid had breached the casing, and was likely charging shallower sandstone beds. This information combined with repeated shallow seismic data acquisition confirmed that an underground blow-out was in progress, which thankfully did not breach the seafloor, charging sandstone beds at 828-878m MSL. Continued attempts to regain control of 2/4-14 and stop the flow into the subsurface using a ‘top-kill’ approach were unsuccessful. Instead the 2/4-15S relief well was used to intersect the open hole section of 2/4-14 and kill the well. The 2/4-14 well was killed by the relief well on 12th December 1989. Upper Jurassic gas and condensate had been flowing into the mapped shallow sandstone unit for up to 326 days. During this period, several data sets were collected to aid in the killing of the well, including flow and temperature measurements, and fluid samples from the well head. 2/4-16: In May 1991, well 2/4-16 was spudded 925m to the southeast of 2/4-14, with the primary objective of evaluating the reservoir potential of the same Upper Jurassic reservoir sandstones indicated by the 2/4-14 well (Saga Petroleum, 1992). The well penetrated 58m of Farsund Fm., but failed to encounter any reservoir sandstones. The absence of Farsund Fm. reservoir sands in the well necessitated a re-evaluation of the seismic data and geological models. These results indicated the Farsund reservoir sandstone tagged by 2/4-14 is pinched-out, or eroded in between the two wells. It was thus concluded that the main zone of interest had to be in a more proximal setting in relation to the two wells, down-dip towards the north. 2/4-18 R: Well 2/4-18 R was spudded in February 1994 with the primary objective to test the reservoir potential of the ‘Upper Jurassic Wedge’. The well drilled 538m of Farsund Fm. in total. Thin, sandstone ‘stringers’ were encountered in what was later defined as the ‘Farsund 2 unit’, and two cores were taken, however neither recovered any reservoir section. Pressure measurements were attempted, largely without success as the sand stringers were mainly thin or cemented. Successful pressure points were however taken from the 2 thickest sandstones (3 and 5m thick respectively), with later fluid sampling attempts being unsuccessful. Insufficient pressure points were available to analyse the fluid density. Post-well petrophysical analysis concluded the Farsund 2 sandstone unit (gross 27m, net 8.2m, ‘main sand’ 5m net) to be hydrocarbon bearing (average hydrocarbon saturation 52%), with 17% porosity at a depth of 5095-5122m MSL. The deeper 5m thick sand encountered in the Farsund 1 unit was water bearing, in a higher pressure regime than the Farsund 2 sandstone (Saga Petroleum, 1994). The 2/4-18R well was completed without well control problems, and was permanently plugged and abandoned as a well with strong shows (NPD fact pages).

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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.

Data evaluation and integration Following the initially disappointing 2/4-18 R well results, re-evaluation of all prospective plays in the licence was undertaken, and included the award of PL333 in 2004. Alongside evaluation of Permian, Triassic, Lower and Middle Jurassic and Cretaceous plays, the Farsund Fm. was further evaluated. Given the history of the Farsund Fm. in PL146/333, this involved integrating a wide range of datasets requiring a multidisciplinary approach – incorporating the expertise of drilling engineers, reservoir engineers, petroleum engineers, well flow/test specialists, high resolution/shallow seismic specialists, petrophysicists, geochemists, and geologists and geophysicists. The re-evaluation of three key datasets/concepts was fundamental to an improved understanding of the Farsund Fm. play: 1) Petrophysics: A reinvestigation of the petrophysics and gas readings of the 2/4-18R well led to a revision of calculated gas saturations up to 80%, however in a thinner net pay of 3m in the Farsund 2 unit sandstone. In addition, the gas saturation was observed to be shut-off abruptly at the base of the sand, implying a gas-down-to (GDT) situation. 2) Material balance: Pressure observations and measurements from the 2/4-14 & 15S wells indicated that there was pressure depletion in the Farsund sandstone reservoir in response to the underground blow out. The 2/4-18 R well, drilled some 4 years after the 2/4-14 well was killed, also indicated a pressure depletion. This observation implied that the 2/4-14 & 18 R wells could be in pressure communication on a production timescale. By combining these observations with fluid composition data (2/4-14 and analogues), known ‘production’ rates from PLT logs, and duration of the flow, it was possible to evaluate the system in terms of ‘Material Balance’. By solving the equation for an ideal gas (given some key assumptions and data from the two wells), it was possible to ascertain the volume of hydrocarbons initially in-place, and thus estimate the present day ‘prospect’ volume. As the data input to this method were not acquired under controlled conditions (pressure, fluid properties and flow rates), there was, inevitably a wide spread of uncertainty on the volumes calculated. Despite this uncertainty the resulting

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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

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Hunting  for  deepwater  subtle  traps:  from  geology  to  technology   Colin  J  Grant,  Francesco  Menapace,  Uisdean  Nicholson,  Dominic  McCormick,  Ciaran  O’Byrne,   Gabriel  Guerra  &  Jim  Pickens  

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

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Hunting for subtle traps: Role of Modern Technology Today, high fidelity marine 3D seismic imaging and advances in computing technology have made the identification of subtle stratigraphic traps using horizon and interval attribute mapping a standardized interpretation workflow. Multiple technologies exist for rapid screening of multi-attribute volumes to discriminate reservoir fairways, trapping elements and reservoir fluids. With older (pre-Cenozoic) plays or at depths that are below the conventional AvO floor, rock properties can make fluid prediction difficult or impossible even if there is good rockproperty calibration available. Shell has developed its own proprietary software for rapid volume screening that provides a fast and efficient way of searching for reservoir fairways. We also have 2D based technologies that can quickly identify stratigraphic pinch-outs. Other technologies that are used routinely to enhance trap understanding are contour or opacity stacking, seismic inversion methods such as elastic impedance inversion, and other quantitative interpretation products aimed at differentiating fluids and reservoirs. However, if the seismic data is bandlimited, noisy or both, painstaking loop-level mapping is often needed to augment or replace these more sophisticated methods. Despite the recent advances in interpretative technology, it is important to remember that the foundations of exploration success in deepwater plays are often laid down at the acreage selection stage. Success begins with selection of the right basin, the right play and the right acreage with the right level of commitment. It involves prudent multi-disciplinary basin evaluation. Often potential fields, 2D seismic, surface geology and play analogue data are only of evaluation. Many of the successes mentioned in this article were made based on solid regional geological foundations that did not rely upon interpretation technology, per se. The Gold Rush Since the discovery of the giant Jubilee field by Kosmos Energy in 2007 in Turonian-age deepwater turbidite reservoirs offshore Ghana, the increased pace of exploration along the West African continental margin can be compared to a gold rush. A similar phenomenon has recently propagated around the eastern seaboard of Africa in light of recent spectacular successes offshore Mozambique and Tanzania, albeit chasing a Paleogene deepwater gas play. This

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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 won’t. 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 PSC’s 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.

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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 PSC’s 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.

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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.

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The Mamba Complex supergiant gas discovery: an example of turbidite fans modified by deepwater tractive bottom currents. Franco Fonnesu

1

Marco Orsi1

1

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 writer’s 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.

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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 Rothschild’s 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? It’s 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: • • • • • •

Fit for purpose business plan adjusted to existing framework conditions The very best exploration team Sufficient financing to support forward plan (3-5 years) Good interaction between Board, Management and Employees Incentives to all staff, openness, ownership and dedication Monitor and measure predicted performance against actual outcomes

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.

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Revived exploration on the flanks of Troll Vegard Gunleiksrud, Tor Veggeland, Richard Olstad, Per Bakøy, André Janke, Kristian Angard, Harald Aubert, Per Avseth and Reidar Müller Tullow Oil Norge AS, Tordenskiolds gt 6B, 0160 Oslo, Norway The giant Troll oil and gas Field (Fig. 1) was successfully discovered and appraised by Shell and Norsk Hydro in the late 70’s and early 80’s. On the northern flanks of Troll, the Fram Field structures were discovered by Mobil and Norsk Hydro during a second successful exploration phase in the 90’s. During the last 30 years eight dry wells have been drilled on the western and eastern flanks of Troll. A general perception (e.g. Goldsmith 2000, Horstad et al 1997) is that more hydrocarbons than what yet is discovered may have migrated into and through the Troll Field. As we understand, there is no established model for spill or leakage out of Troll. Four wells East of Troll targeted the spill route out of Troll, but the structures were proven dry. Tullow Oil Norge, as operator of the partnerships PL 550 and 551, has identified several prospects both on the migration route into the Troll Field and on the migration route out of the field. The model for the significant Kuro prospect implies a new explanation of the controlling mechanisms of the Troll Field hydrocarbon contacts. Tullow Oil will operate one well in 2013 (PL551) and one well in 2014 (PL550) in order to test some of the identified prospectivity. As the flanks of the Troll Field had been thoroughly explored through several exploration phases during three decades, we tried to use some alternative approaches in order to define prospectivity. Our highest ranked prospects on the flanks of Troll are to a large degree resulting from the following “not-so-traditional” elements: •

Ultra Far Offset seismic data – valuable info from data formerly regarded as “garbage”

•

Injectite sandstone reservoirs – not a traditional play in this area

•

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)

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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”.

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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.

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Abstract:

The 35/9-6S Titan Discovery

Torodd Nordlie, Egil Lind and Kristine Rossavik RWE Dea Norge AS The Titan discovery was made by the 35/9-6S well drilled in November/December 2010 in PL420 in the Northern North Sea approximately 16 km west of the Gjøa Field. PL420 was awarded in APA 2006 and the license is operated by RWE Dea with 30% equity. Partners are Statoil with 40% and Idemitsu with 30%. The Ryggsteinen Ridge has been underexplored for many years due to poor seismic imaging (complex overburden) and overlooked positive signs from two old wells regarded as disappointing at the time of drilling (35/11-1 and 35/8-5S). The recent exploration success on Grosbeak, Titan and Skarfjell has changed this picture, and opened up for follow up potential on the Ryggsteinen Ridge and a high exploration activity level. The primary exploration target for the Titan well was to prove petroleum in Middle Jurassic reservoir rocks (the Brent Group). The secondary exploration target was to prove petroleum in Upper Jurassic reservoir rocks (the Heather Formation) and in the Lower Jurassic reservoir rocks (the Cook Formation). Oil and gas was proven in the Titan well over a gross column of more than 400 meters at five reservoir levels in the Heather Formation, the Brent Group, the Drake Formation and the Cook Formation. The well was drilled to a vertical depth of 3664 meters and was terminated in Upper Triassic rocks. Several faults were penetrated in the well and have created some uncertainty to the true thickness of the Callovian and Cook reservoir units. The reservoir levels in the Titan well are in different pressure regimes, and no hydrocarbonwater contacts were encountered. Oil was discovered in the two upper reservoir zones and gas/condensate in the three lower reservoir zones. The PVT modeling suggests that the zones containing gas/condensate will contain oil deeper on the structure. The oil and condensate samples from the five reservoir zones also have comparable geochemical characteristics, so the only difference is the amount of methane. The Titan well was drilled on a structural closure, and further to the south faults with possible sealing potential are mapped. Since no oil-water contact was penetrated in the well it is uncertain if the discovery is just the four-way structure or if Titan could be a hanging-wall fault trap with a larger areal extension. Due to these uncertainties appraisal drilling is needed to ascertain the volumes of the Titan discovery. The current P50 Titan recoverable resource estimate is 12 million Sm3 of oil equivalents. A 3D seismic survey (RD1201) was acquired by RWE Dea in the spring 2012. The survey was originally planned for the spring 2011, just after the discovery well, but was one year delayed due to fishery restrictions. As a result of the Skarfjell discovery in PL418 the RD1201 survey was extended into PL418 and PL378. The new 3D seismic data will be used to position the

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Titan appraisal well planned to be drilled late 2013 and to map further exploration potential in the PL420 license.

 

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Extended  abstract:     The  35/9-­‐7,  Skarfjell  Discovery,      The  Skarfjell  Discovery:       Jens-­‐Ole  Koch,  Sabine  Rössle,  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  Gjøa  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   Gjøa,  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.    

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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

IH2 ODT 35/9-7 at 2660 m TVDSS

General Spillpoint at 2990 m TVDSS

 

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Constructed  Top  Oxfordian  Turbidites  IH2  Depth  Map                  

35/9-­‐7  CPI   showing  very   good   reservoir   quality  of   Intra  Heather   Sandstones  1   &  2.  

   

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Arbitrary   seismic  line     from  the   RD1201  3D   seismic   survey  across   the  Skarfjell   Discovery  

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