1. INTRODUCCIÓN
1.3. Antecedentes Teóricos
1.3.6. Ensayos
1.3.6.1. Permeabilidad
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
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
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 km2 3D OBC in 2008. In 2009 a 1675 km2 3D Geostreamer survey (the first on the NCS) was acquired over the Haugaland High. Following the Johan Sverdrup discovery 2600 km2 Broadsize 3D was acquired in 2010 and 11 (the first commercial survey on the NCS). These broadband seismic surveys are improving the imaging of the whole sequence from sea bottom into basement.
The main new elements in the understanding of the petroleum habitat of the Haugaland High are:
•Efficient migration of light oil into the prospects the last 1.5 million years through multi-‐Darcy Volgian age sand when the reservoirs where beneath a depth corresponding to a temperature of more than 800 C. Light under saturated oil flanking saturated oil and gas discovery due to Late Miocene pressure barriers
•Late Miocene inversion and Pleistocene subsidence have significant influence on the current structuring and migration and re-‐migration. Glacial induced istostasy has also affected the re-‐
migration
New reservoir targets have been established on the Haugaland High:
•Continental proximal reservoir rocks in the Edvard Grieg discovery.
•Porous producible basement rocks in the Luno South and Tellus discoveries.
•Transgressive marine Volgian age sandstone with extremely good reservoir properties overlying marine and fluvial Upper Jurassic sediment in Johan Sverdrup discovery.
•Lower Cretaceous/Upper Jurassic shelf sandstone reservoirs along the west flank.
•Valanginian age calcareous porous sandstone in Tellus.
• Porous Zechstein has been observed in 4 wells 16/2-‐6, 16/2-‐7, 16/2-‐16 and 16/3-‐5
These new concepts have opened up for an extensive exploration campaign in surrounding licenses on the southern Utsira High. The following prospects will be drilled in 2013:
• 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.
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.
Figure 2: Seismic and geoseismic section through the 16/2-‐6 and 16/2-‐8 wells. A black peak represents an increase in acoustic impedance. The envelope of the Jurassic can be interpreted on the seismic and is marked by arrows. Location of line can be found in figure 1.
The first well to be drilled to test this concept, and thus the discovery well of Johan Sverdrup, was the 16/2-6 well. Following the positive results here, which included a production test (DST) showing excellent reservoir properties and a laterally extensive upper Jurassic reservoir, this greatly increased the probability of finding oil in a more westward position, closer to the Utsira high itself.
The 16/2-6 well sits in a location where the Jurassic reservoir thickness is fairly thin (24 meters) and thus within one seismic cycle. The 16/2-8 well was drilled to test the Jurassic potential further to the west. It was placed in a position closer to the main boundary fault to the Utsira High - higher on structure and in an expected thick Jurassic package. The well found a 73 m thick Jurassic reservoir with a net-gross of 0.97, average porosity of 29% and multi-Darcy permeability. As the pressure data confirmed communication with the 16/2-6 well, it was now clear that what is now called the Johan Sverdrup field was a large discovery.
The reservoir in Johan Sverdrup consists mostly of late Jurassic-early Cretaceous coarse to very coarse sandstones (Draupne Fm.) which overlies fluvial to shallow marine Middle Jurassic sandstones that form the lower part of the reservoir section. The Draupne sandstone consists mostly of gravity flow deposits laid down along and at the front of fan-deltas directly fed from the basement high and reworked by marine currents.
Marine reworking of the sediments has made the Draupne sandstone nearly mud-free, thus enhancing the reservoir properties which show porosities in the range of 0.24-0.32 and permeabilities from 1-30 Darcy. The fluvial to shallow marine Middle Jurassic reservoir (Vestland Gp.) has a more complex facies distribution. New appraisal wells have revealed varied reservoir properties – variations in NTG and sand distribution that are below seismic resolution. In Late Tithonian age the Karmsund Graben was rapidly drowned, causing
formation of phosphatic-carbonate condensed section that preceded the deposition of deep water hot shales (Draupne Fm.) in the eastern part of the basin. At the same time, some fine spiculitic sandstones where deposited into the margins of the Utsira basement high, representing the younger portion of the reservoir.
An extensive appraisal drilling program has been carried out and is still ongoing in both the Statoil-operated PL265 license and in the Lundin-operated PL501 license. Special focus on data acquisition with extensive coring, wireline logging and dynamic data has been essential to obtain a better understanding of the reservoir and how to develop the field. The current plan for production start-up is 2018.
Including the 16/2-6 well with spud in July 2010, 14 wells have been drilled - with an additional 5 sidetracks, giving in average 50 days between each new data point. This pace will continue in 2013.
This presentation will aim at discussing some of the issues that are addressed with the appraisal wells and present some results to illustrate this.
One of the major uncertainties in the field relates to depth conversion. As the top of the reservoir is generally flat, and also since the reservoir envelope is rather thin in some areas, a few meters shift up or down can move the contact quite a long distance laterally, with implications both for volume and drainage strategy. The 16/5-2 S well serves as an example of this – the well came in dry as the overburden velocities were higher here than predicted by the models.
The contact itself is also uncertain. Most wells show an oil-water contact of around 1921-1925 m TVD MSL, but the 16/2-10 well proved a contact of 1934m. The recent 16/2-16 well (and sidetrack 16/2-16 A T2) was drilled with one of the objectives to define contact, and as the deep contact was found only in the sidetrack, this will help in constraining the area of the deep contact in this area.
The wells drilled so far have confirmed that we seem to have a reasonable good grip on the envelope of the Jurassic, and as all wells so far have proven a tight Triassic, this is also the envelope of the main reservoir.
Even though the reservoir container is reasonably well understood, the variation of properties within the container is more difficult to get a grip on, as the seismic not has proven to be of very much help - as wells with a similar seismic expression have proven quite different reservoir facies.
So far the wells have been placed in a secure distance away from the main fault that defines the western edge of the graben, to reduce the risk of encountering alluvial conglomerates. The planned 16/2-17 well (Q2 2013) will be drilled in a position close to the fault to investigate this area.
Even though the Triassic rock has proven tight, there could be reservoir potential in deeper strata, such as in fractured basement proven by the 16/3-4 and 16/2-12 wells, and also in Permian carbonates, which is a secondary target for the ongoing 16/3-5 well, drilled in a setting where the Triassic is absent.
The field extent to the south and east is controlled by the contact, but towards the north and the west, the extent is more controlled by the presence or absence of reservoir. The 16/2-9 S well was drilled in 2011 in a small graben north of the main Johan Sverdrup graben, and encountered spiculite – a rock made up of siliceous sponge spicules that dissolve and can create good secondary porosity but usually very poor permeability. The very modest reserves in this graben are not considered part of Johan Sverdrup.
Given the disappointing results of the 16/2-9 S well, the results of the 16/2-12 Geitungen well, drilled in 2012 on a basement terrace midway between the spiculites encountered in 16/2-9 S and the Johan Sverdrup field, was very welcome. This well was regarded as an exploration well with a risk on reservoir presence – but when the well came in with a good reservoir, and only a thin layer of fine spiculitic sandstone at the top, the well was reclassified as an appraisal well – as the pressure data indicated communication with Johan Sverdrup.
Following up the positive results from Geitungen, it is possible that even more resources may be added to the Johan Sverdrup volumes this year, both to the north and to the west. An exploration well will be drilled to test the Torvastad prospect, located to the north of the 16/2-9 S well. Also this year, a well will be drilled to the west of the main fault in the area west of the 16/2-14 well, to test if sands are present on the basement high itself. This prospect is called Cliffhanger North.
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.
The licence partnership is comprised of Faroe Petroleum, Tullow Oil and Suncor Energy. The licence was awarded in the APA 2006 licencing round.