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Petroleum Systems of the Central Atlantic Margins, from Outcrop and Subsurface Data

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Coastal exposures of Mesozoic sediments in the Wessex basin and Channel subbasin (southern UK), and the Lusitanian basin (Portugal) provide keys to the petroleum systems being exploited for oil and gas offshore Atlantic Canada. These coastal areas have striking similarities to the Canadian offshore region and provide insight to controls and characteristics of the reservoirs. Outcrops demonstrate a range of depositional environments from terrigenous and non-marine, shallow siliciclastic and carbonate sediments, through to deep marine sediments, and clarify key stratigraphic surfaces representing conformable and non-conformable surfaces. Validation of these analog sections and surfaces can help predict downdip, updip, and lateral potential of the petroleum systems, especially source rock and reservoir.
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Sedimentary Basins: Origin, Depositional Histories, and Petroleum Systems 1
Petroleum Systems of the Central Atlantic Margins, from Outcrop and
Subsurface Data
Wac h, Grant
Dalhousie University
1355 Oxford Street
Halifax, Nova Scotia, Canada, B3H 4R2
e-mail: Grant.Wach@dal.ca
Pimentel, Nuno
Centro de Geologia, Faculdade de Ciências da
Universidade Lisboa
Campo Grande C-6
1749-016 Lisboa, Portugal
e-mail: Pimentel@fc.ul.pt
Pena dos Reis, Rui
Centro de Geociências, Faculdade de Ciências e
Tecnologia da Universidade de Coimbra
Lg Marquês de Pombal
3000-272 Coimbra, Portugal
e-mail: penareis@dct.uc.pt
Abstract
Coastal exposures of Mesozoic sediments in the
Wessex basin and Channel subbasin (southern UK),
and the Lusitanian basin (Portugal) provide keys to the
petroleum systems being exploited for oil and gas off-
shore Atlantic Canada. These coastal areas have
striking similarities to the Canadian offshore region
and provide insight to controls and characteristics of
the reservoirs. Outcrops demonstrate a range of deposi-
tional environments from terrigenous and non-marine,
shallow siliciclastic and carbonate sediments, through
to deep marine sediments, and clarify key stratigraphic
surfaces representing conformable and non-conform-
able surfaces. Validation of these analog sections and
surfaces can help predict downdip, updip, and lateral
potential of the petroleum systems, especially source
rock and reservoir.
Introduction
Outcrops from analogous outcrop sections along
the UK and European margins may provide new play
opportunities when the petroleum systems of the Cen-
tral Atlantic margin are explored and developed
(Fig. 1). These outlier basins typically are marked by
significant unconformities that can mark key intervals
for reservoir generation and reservoir distribution, and
hiatal surfaces that may provide key data on condensed
and sediment starved intervals. These basins have rela-
tively complex geological histories, multiple sources of
sediment input, source rock analogs, and variable dep-
ositional settings. The Wessex-Channel basins of
southern England and the Lusitanian basin of Portugal
provide excellent outcrops to examine these intervals
and develop new concepts that can be applied to the
Western Margin where there are wells and significant
production, but no outcrops of producing intervals
(Fig. 1).
The Wessex and Channel basins lie on Paleozoic
basement deformed during the Variscan Orogeny,
which culminated during the late Carboniferous. In
early Mesozoic, north-south extension created a series
of east-west faults possibly related to reactivation of
Variscan thrusts. Extensional activity lasted until the
end of Barremian times and possibly well into the
Aptian, while thermal relaxation continued until the
end of the Cretaceous.
The Lusitanian basin is an epeiric basin on the
coastal areas and offshore western Portugal. It is
bounded to the east and west by emergent Paleozoic
highlands that provide the source of siliciclastic sedi-
ments to the basin. The basin provides good outcrop
analogs for a range of depositional environments rang-
ing from fluvial to estuarine mixed sediments and
coastal platform carbonates.
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Background and Previous Work
Srivastava and Verhoef (1992) established
boundaries for the basins of the Central Atlantic that
remain valid today with minor modifications. Hiscott et
al. (1978) helped to establish the tectono-stratigraphic
events between the Moroccan margin and eastern
North America and determined that rates of sedimenta-
tion were relatively constant along the basin margins
but there was some increase in rifting along the New-
foundland margin (Hiscott et al., 1990). Sinclair et al.
(1994) and Shannon et al. (1995) examined wells from
the Jeanne d’Arc basin offshore Newfoundland with
those of the Porcupine and Moray Firth basins with the
objective of determining similarities in basin fill and
the tectonic controls on reservoir architecture. Wu's
(2007, 2013) work on crustal structure of the Scotian
margin correlated the refraction seismic data from the
Scotian and Moroccan margins, noting the similarities
and key differences between the margins. The Channel
and Wessex basin outcrops have been investigated in
several studies (e.g. Channel basin - Ruffell and Wach,
1991; Wessex Basin - Hesselbo et al. 1990). Lusitanian
basin studies include those of Cunha and Pena dos Reis
(1995), and Dinis et al., (2008 and references therein).
Petroleum Systems
An understanding of basin evolution is crucial to
deciphering the petroleum systems and controls on sed-
imentation and the depositional history of the Eastern
margin basins. Regional tectonic events coupled with
eustatic variations had direct impact on the petroleum
systems.
Wessex and Channel Basins
Three major fault zones divided the Wessex
basin into five subbasins, including the southernmost
Channel basin (Fig. 2). Lower sea level in the latest
Jurassic to Early Cretaceous created two depocenters
separated by the London Brabant massif but with
slower sedimentation rates in the northern basins.
Within the basin there were minor unconformities and
non-sequences due to eustatic changes and variable
rates of local tectonic and regional tectonism. These
were superseded by a major unconformity cutting the
Mesozoic section in southern England associated with
later Cimmerian tectonism; the unconformity formed
in a late extensional setting. The deposition of the
Aptian-Albian Lower Greensand in southern England
marked the end of the late Cimmerian event.
Source rock, maturity and migration
Bray et al. (1998) recognized four major heating
events in the Wessex basin complex (Fig. 2): mid-Tri-
assic to early Jurassic, early Cretaceous, mid-Tertiary,
and late Tertiary. Due to basin tectonics (periods of
uplift and burial), maturity levels vary within different
subbasins of the Wessex. There are two potential
(depending upon maturity) Jurassic source rocks; the
lower Oxfordian Clay and Kimmeridge Clay, and a
proven source rock in the Lower Jurassic Lias Group.
The Kimmeridge Clay consists of the Type II and III
kerogen whereas the Oxfordian and Lower Lias con-
sists of Type II, III, and IV (Ebukanson and Kinghorn,
1985). The Kimmeridge and Oxford Clay have high
total organic carbon (TOC) content (up to 20%) how-
ever these rocks are not sufficiently buried to become
mature (Farrimond et al., 1984 cited in Underhill and
Stoneley, 1998). TOC values in the black shales of the
Lower Lias have values recorded up to 8% in a Type II
kerogen (Ebukanson and Kinghorn, 1985).
The Lias Group shows large variations in matu-
ration along the basin due to regional tectonics and
subsequent compartmentalization of the hydrocarbon
systems. This compartmentalization is apparent in the
Kimmeridge-5 well which experienced source rock
generation in the early Cretaceous to mid-Tertiary
(Bray et al., 1998). It is during this interval within the
early Cretaceous that these hydrocarbons entered the
oil window; i.e., the critical moment (Fig. 2). Underhill
and Stoneley (1998) suggest that peak generation is
around middle to late Cretaceous. Other areas of the
basin, for example the Wytch Farm Block, does not
reach maturity at any time during the Jurassic and early
Cretaceous due to shallow burial.
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Reservoir rock
Within the Wessex basin, siliciclastic units have
the highest reservoir rock potential (Underhill and
Stoneley, 1998) having high primary porosities, high
net:gross values, and sufficient lateral extent to hold
commercial oil accumulations. Examples of potential
and producing reservoirs are the lower Triassic Sher-
wood Sandstone with variable porosity that are facies
dependent: fluvial channel sands (6-18%), sheet flood
deposits (14-22%) and eolian sandstones (14-27%).
The thick, fine-grained early Jurassic Bridport Sands
have porosities up to 15% based on outcrop exposure
and up to 32% in the Wytch Farm field based on core
data.
There are other units having higher reservoir risk
due to the reduction in permeability, limited lateral
extent (e.g., Permian eolian sandstone), or a high con-
tent of fine-grained material (e.g., Thorncombe
Sandstone), or the fractured mid-Jurassic Frome Clay.
Some carbonate units also act as good reservoirs when
secondary porosities are created by fracturing and/or
dissolution of cement. These include the Middle Juras-
sic Inferior Oolite and Portland Limestone.
Trap
The traps in the Wessex basin were primarily
structural rather than stratigraphic and can be divided
into two major tectonics events: extensional in the
Mesozoic and compressional (basin inversion) during
the Cenozoic. Extensional faulting began during the
Paleozoic Variscan fold and thrust belt, progressing to
the Late Cretaceous (Underhill and Stoneley, 1998).
The extensional tectonics subdivided the basin into
several fault blocks, tilting the strata, and thus creating
potential traps, similar to fields on the Grand Banks.
Hydrocarbon exploration shifted to these buried and
tilted extensional blocks which are related to the struc-
tural plays in the Wytch Farm and Wareham oil fields,
whereas structures related to the Cenozoic-based inver-
sion are periclinal traps developed from the late
Cretaceous to early Cenozoic (Underhill and Stoneley
1998).
Seal
Most of the reservoir rocks are sealed by the
presence of thick shale intervals or by thin, imperme-
able layers. Some examples of these are the Triassic
Aylesbeare Mudstone Group overlying Permian eolian
sandstone, Mercia Mudstone overlying the Sherwood
Sandstone, and potentially the Kimmeridge Clay over-
lying the lower Jurassic reservoirs. Structural tilting of
the blocks during extensional tectonics (Permian to
Cretaceous) and later by structural inversion (Ceno-
zoic) may have contributed to the sealing of the
reservoirs. In these cases, lateral traps which developed
are dependent on lithology, thickness (sand:shale ratio),
and the amount of fault displacement. Inversion could
initiate remigration of hydrocarbon into shallower res-
ervoirs, but drilling to target these plays suggests the
faulting (which acted previously as conduits for the
migration of hydrocarbon) became barriers or seals as a
result of compressional forces (Selley and Stoneley
1987) and perhaps cementing of fault traces through
diagenesis.
Portuguese Margin
Portuguese margin basins
The Lusitanian basin is bounded to the east and
west by emergent Paleozoic highlands that provide the
source of siliciclastic sediments to the basin (Fig. 3).
The Berlengas highlands separate the Peniche basin
offshore, to the west from the Lusitanian basin. The
Peniche basin is open to the Atlantic, has no wells, and
has limited proprietary seismic data in the region. It is
expected that the geology progresses from non-marine
and littoral environments to shelf, slope, and basin
floor settings. There may be similar basins outboard,
west of the Peniche basin.
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Source rock and maturity
The Lusitanian basin geological record contains
different units having source-rock potential, including
basement Paleozoic deep-marine black-shales, and tur-
bidites, with hydrocarbon generation and migration
into Mesozoic reservoirs (Uphoff, 2005; Pena dos Reis
and Pimentel, 2010a, 2010b). Lower Jurassic (Sinemu-
rian-Pliensbachian) marls and Upper Jurassic
(Oxfordian) laminated marly limestones are the two
major units having high TOC; however, Hettangian
(Dagorda Formation), Kimmeridgian (Abadia Forma-
tion), and Cenomanian-Turonian (Cacém Formation)
should also be considered (Spigolon et al., 2011).
The Lower Jurassic marine marly black shales
(Duarte and Soares, 2002) up to one hundred meters
thick, are the lower part of the Brenha Group, which
extends across the basin and contains a highly variable
TOC (up to 22.5 wt%; Duarte et al., 2012) of kerogen
Types I-II (Spigolon et al, 2010). These homoclinal
carbonate ramp deposits dip to the northwest and are
related to the initial opening of the Lusitanian basin to
marine influences. Two significant organic-rich maxi-
mum flooding surface intervals (Água de Madeiros
Formation and Vale das Fontes Formation) have been
studied in detail, regarding their TOC values, isotopes,
palynofacies, etc. (Duarte et al., 2010, 2012; Silva et
al., 2010, 2011; Poças Ribeiro et al., 2013).
The Upper Jurassic source rock (Cabaços Forma-
tion) is composed of marly limestones deposited in
lacustrine to lagoonal and coastal environments
(Spigolon et al. 2011; Silva et al. 2013). TOC values in
darker layers usually range from 2 to 5 wt%; kerogen
types are variable, but there is a predominance of Type
II-III. Their deposition overlies a major regional Callo-
vian unconformity and records the early syn-rift
transgressive interval during the Oxfordian. The pre-
vailing paleogeographic conditions were controlled by
a north-northeast/south-southwest oriented depression,
fed by a fluviodeltaic network from the north-north-
east, towards the deepening areas developing more to
the south-southeast (Pena dos Reis et al., 2011). The
richest intervals are not strictly synchronic, but they are
widespread basin-wide, and have no preferential sec-
tors (Silva et al., 2013).
Maturation of both source rocks has been mod-
eled, based in lithology and thickness well data,
calibrated by vitrinite reflectance data (Teixeira et al.,
2012, 2014). Both Jurassic source rocks have attained
the hydrocarbon generation window, although not
everywhere in the basin as a result of the highly hetero-
geneous basin’s subsidence and overburden, especially
in the Late Jurassic.
Non-mature Lower Jurassic source rocks are
known in outcrop, namely at the Peniche, Montemor-o-
Velho and São Pedro de Muel sections (Oliveira et al.,
2006; Silva et al., 2010; Spigolon et al., 2011; Duarte
et al., 2012), but the same units have reached maturity
in several exploration wells in the basin (Teixeira et al.,
2012, 2014). Also, non-mature Upper Jurassic source-
rocks are known in different outcrops, such as Cabo
Mondego or Montejunto (Spigolon et al., 2011),
whereas they reached the oil window in nearby wells
such as SB-1, FX-1 and CP-1 (Teixeira et al., 2012,
2014). This situation points to a very important role of
differential subsidence along the basin, both in time
and space.
As a general statement, it may be considered that
the Lower Jurassic source rock is mature for oil in the
north sector of the basin and mature for gas in the south
sector, whereas the Upper Jurassic source rocks may be
not mature in the north sector and are mostly mature in
the south sector (Teixeira et al., 2012, 2014).
The different geological setting of these two
Jurassic organic-rich intervals, has generated geochem-
ically distinct types of hydrocarbons. Therefore,
detailed studies of oil seeps and oil shows have
revealed the presence of mature oils from both source
rocks, in different depositional and tectonic settings.
Good examples are the presence of Lower Jurassic
related oils identified in Cretaceous sandstones close to
diapir walls at Praia da Vitória and Leiria, as well as
Upper Jurassic related oils identified in Oxfordian
limestones close to a diapir wall at Torres Vedras
(Spigolon et al., 2010).
Reservoir rock
Several siliciclastic and carbonate units have
good reservoir potential in the Lusitanian basin. These
include Late Triassic alluvial-fan to fluvial red beds
(Silves Group), Middle Jurassic (Candeeiros Group)
and Late Jurassic (Montejunto Formation) fractured
carbonates and biohermal build-ups, Late Jurassic tur-
biditic (Abadia Formation), and fluviodeltaic
(Lourinhã Formation) sandy lobes and channels. More-
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over, the sedimentary infill of the basin presents at its
uppermost section abundant Cretaceous fluvio-estua-
rine sandy deposits (Torres Vedras Group) related to
the breakup unconformities (Dinis et al., 2008).
These Cretaceous units have very good reservoir
properties but have been disregarded as a potential res-
ervoir due to their high stratigraphic position and lack
of apparent seal. However, these same units are
expected to be present in offshore areas, namely in the
deep offshore Peniche basin where the more distal
location could provide adequate seal facies. Current
exploration in these areas make it increasingly import-
ant to understand the reservoir potential. Two
analogous outcrops have been studied in detail to
understand facies relationships and heterogeneities –
the Ericeira outcrop, 35 km northwest of Lisbon, and
the Crismina outcrop, 30 km west of Lisbon.
The outcrop at Ericeira lies along the western
part of the outcropping Lusitanian basin. The succes-
sion comprises the unconformity-bounded surface of
Late Aptian age (Rey et al., 2006). This unconformity
is marked by the abrupt shift from highstand carbon-
ates in the Aptian (Crismina Formation) to terrestrial
low gradient coastal sediments (Rodízio Formation)
comprising red and grey mottled silt and clays and flu-
vial channels consisting of fine-grained to pebble-sized
sediments. The coarser grain size may reflect reactiva-
tion of faults along the western margin of the basin
(Dinis et al., 2008); basin margin syndepositional faults
are visible in the Ericeira section. The succession
abruptly fines up into medium to dark grey shales
before the resumption of small channel deposition,
marking a forced regression at the base of the Albian.
The section at Crismina, is located along the
southwestern edge of the Lusitanian basin. The section
is similar to Ericeira, also representing the Late Aptian
breakup unconformity, but between more distal facies
of the two aforementioned formations (Rey et al.,
2006). The outcrop shows an abrupt transition from
shallow marine and lagoonal carbonates in a highstand
during which there was limited siliciclastic sediment
input to the basin. There is an erosive surface and an
abrupt transition to clean white quartzose sands depos-
ited in estuarine conditions, with evidence of subtidal
channels and barforms. The succession rapidly shal-
lows, and coarser grained sediment and trough cross
bedding reflect further progradation of sediment into
the basin and deposition of fluvially derived sediments
sourced from the Paleozoic highlands that bounded the
basin to the west (Dinis et al., 2008). These highlands
separate the Peniche basin from the most southern sec-
tors of the Lusitanian basin (south of the Lousã-Caldas
fault) and their erosional remnants are expressed today
as the Berlengas Islands.
Trap
The traps in the Lusitanian basin are predomi-
nantly structural. The Late Jurassic rifting phase and
the Late Cretaceous–Eocene alpine inversion, followed
by the Miocene Betic inversion due to Iberia-Africa
collision, caused a significant structural complexity
and created a tectonic block puzzle and both local sub-
sidence and later uplift with movement of salt. This
structural framework allowed the contact of different
source rocks, migration pathways, and reservoir units,
sometimes not completely sealed. Some major folding,
induced by deep salt doming combined with clay-rich
capping units, is likely to have trapped late Jurassic
hydrocarbons in fractured limestones, and coarse-
grained Kimmeridgian turbidites. Salt movement also
has had an important role in hydrocarbons accumula-
tion, focusing the vertical migration of Early Jurassic
hydrocarbons upwards into Cretaceous siliciclastics
around the diapirs. These traps are proven by some
hydrocarbons staining and fracture oil seeps associated
with salt walls related to reactivation of deep basement
faults.
Seal
Fine-grained clays and evaporates of the Het-
tangian Dagorda Formation (Palain, 1976) and thick
clays of the Maastrichtian Taveiro Formation (Pena dos
Reis, 2000) are certainly the most effective seals in the
basin. The Dagorda Formation consists of compacted
red clays containing variable amounts of gypsum,
halite, and dolomite, up to hundreds of meters thick. It
is intensely deformed in areas closer to basement
faults. The clayey Taveiro Formation, up to 200 m
thick, includes sandstone and carbonate, capping the
Mesozoic areas north of the Lousã-Caldas fault.
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There are several other clay-rich units, but they
rarely act as a perfect seal due to their frequent interca-
lation with sandy layers as is the case of the Upper
Jurassic and Lower Cretaceous units. However, Upper
Cretaceous and Cenozoic shale units may have acted as
important seals, particularly in more subsiding or distal
areas of the basin.
Newfoundland Margin–Grand Banks
Recent discoveries by Statoil in the deep-water
basins of the Flemish Pass have expanded the explora-
tion potential and proven viable petroleum systems
outside the traditional areas of the Grand Banks where
exploration success has driven development for nearly
four decades (Fig. 4). The Jeanne d’Arc Basin includes
production from the Hibernia, Terra Nova, White Rose,
and Hebron fields. Hebron has been the latest field
development with estimates of three billion barrels in
place but of a heavier grade oil (21 degree API)
(Enachescu 2006). Baur et al. (2009) suggest that the
Jeanne d’Arc basin formed as failed rift basin, first by a
Late Triassic event and then slow stretching from the
Late Jurassic though to the Early Cretaceous, although
the latter did not have a significant impact on thermal
maturity. Immediately to the south of the Jeanne d’Arc
basin are the Carson basin and to the east of the Carson
is the Salar basin on along the eastern edge of the
Grand Banks. These basins lie on the present-day slope
of the Grand Banks and began as a network of inter-
connected rift basins (Enachescu, 2006), that formed
with the opening of the Atlantic Ocean and break-up of
Pangea in the early Mesozoic.
The Mesozoic and Cenozoic sedimentary fill of
the Carson basin on the eastern Grand Banks of New-
foundland has been penetrated by four wells. Wielens
et al. (2006) indicate that the Salar and Carson basins
are underlain by thicknesses of earliest Jurassic salt
(Argo Formation), thicker on the on the western mar-
gins of the basins. They recognize that stratigraphic
units could be correlated between the Carson and
Jeanne d’Arc basins and that there are clear eustatic
overprints across both basins. In the Jurassic, deposi-
tional conditions are inner neritic to marginal marine
based on palynomorph, foraminiferal, and ostracod
data.
Source rock, maturity and migration
In the Jeanne d’Arc basin the Egret Member of
Kimmeridgian age is a mature marine source rock con-
taining some terrigenous material and having TOC
values between 4-6% and Hydrogen Index from 100-
610 mgHC/ gTOC (Baur et al. 2010). Modelling of the
petroleum systems of the Terra Nova oil field suggests,
rather than one source from the Egret Member as previ-
ously thought, that there is potential for an additional
kitchen area between the Terra Nova and Hibernia oil
fields. This could impact understanding of the petro-
leum systems of the Mara, Hebron, Ben Nevis,
Springdale, and White Rose fields. In the Carson basin,
the Mesozoic section includes reservoir and seals but
source rocks similar to the Jeanne d’Arc Basin have not
been proven (Wielens et al., 2006). Bauer et al. (2009)
modeled a source rock in the deeper regions of the Car-
son basin that would be equivalent to the Egret in the
Jeanne d’Arc basin and postulate that hydrocarbons
could be generated and be trapped in Lower Cretaceous
or Cenozoic reservoirs.
Reservoir rock
Siliciclastic deposition from highlands border-
ing the Jeanne d’Arc basin are the source of the
majority of the reservoir prone sediments, which have
porosities ranging between 15-25% and permeabilities
to 100md (Baur et al., 2009). The formation of traps
was during the Berriasian (140 ma) during deposition
of the Hibernia Formation; a second phase occurred
during the Paleocene (53 ma) followed by a constant
pattern of migration for the remainder of the Cenozoic
(Baur et al., 2009).There are several reservoir and seal
pairs. The most effective seal, the Fortune shale unit,
deposited during the latest Tithonian, represents a
transgressive succession, capping the coarser grained
Jeanne d’Arc reservoirs.
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Trap
The formation of fault-bounded anticlinal traps
was during the Berriasian (140 ma) during deposition
of the Hibernia Formation; a second phase occurred
during the Paleocene (53 ma) and then with a constant
pattern of migration for the remainder of the Cenozoic
(Baur et al., 2009).
Seal
There are several reservoir and seal pairs. The
most effective seal, the Fortune shale unit, deposited
during the latest Tithonian, represents a transgressive
succession, capping the coarser grained Jeanne d’Arc
Basin siliciclastic reservoirs.
Enachescu (2006) reports potential petroleum
plays in sandstone trapped in fault blocks of the Jeanne
d’Arc, Hibernia, and Avalon/Ben Nevis units. The
Jeanne d’Arc Formation sandstones have been depos-
ited during Late Kimmeridgian-Tithonian in stacked
incised valley systems and inner neritic environment.
This play has been successful at the Terra Nova and
Hebron fields and it is expected to extend to other areas
in the south-eastern Jeanne d’Arc basin. Oil pay is
found in the Hibernia sandstone reservoir in several of
the fields surrounding the parcels. Similarly, Avalon
and Ben Nevis sandstones contain oil and gas in sev-
eral of the fields, and petroleum potential is also
recognized in the Upper Cretaceous- Late Cenozoic
sandstone members.
Scotian Basin
The Mesozoic to Cenozoic Scotian basin was ini-
tiated during the Triassic syn-rift to lower Jurassic
post-rift phase on the Atlantic margin; terrestrial silici-
clastic sediments and evaporites mark this phase (Fig.
5). In the Middle Jurassic, the Abenaki carbonate plat-
form developed as an enigmatic succession of platform
carbonates juxtaposed with sands and shale of the
Sable Delta complex (Eliuk and Wach, 2008). The
majority of the succession is a passive margin basin fill
of sand and shale sequences deposited in response to
global relative changes in sea level. In the later Jurassic
and Cretaceous, the Sable and Laurentian deltas pro-
duce transgressive and regressive packages of deltaic,
shelf margin, and slope deposits (Wade and MacLean
1990; Kidston et al., 2002).
There are two active petroleum systems currently
producing in the Scotian basin, both gas prone. The
five field ExxonMobil Sable project (1999-present)
produces from siliciclastic deltaic and shallow marine
reservoirs having some condensate; production is
scheduled to end later this decade. The Encana Deep
Panuke project (2013) has begun production of gas
from the Late Jurassic Abenaki carbonate margin and
full production is scheduled for the year-end. A third is
the light oil and condensate production from deltaic
and shallow marine reservoirs in the now decommis-
sioned Lasmo (later PanCanadian-Encana) Cohasset-
Panuke project (1992-99); Panuke directly overlies the
Deep Panuke field.
The western Shelburne subbasin is located in
deep water and remains essentially untested for hydro-
carbons, with but a single well drilled to test a shallow
(Cenozoic) stratigraphic anomaly on the deep water
Scotian Slope. An untested delta prism is interpreted in
deep water on the western margin (Wade and MacLean,
1990). The subbasin is on track for future exploratory
drilling following completion by Shell (2013) of a large
(~8100 km2) regional WAP 3D seismic program.
Source rock and maturity
Precisely identifying all source rocks on the Sco-
tian Margin is a significant challenge with a mix of
known and suspected intervals (OETRA, 2011). The
Late Triassic rift syn-rift successions remains unproven
but hold potential for Type I kerogens from lacustrine
sources facies. Similarly, there are thick, late pre-rift
evaporate deposits (Hettangian Argo Formation) that in
addition to creating numerous structural configurations
and traps may cap a hypersaline shallow marine suc-
cession (Type II). A lower Jurassic (Pleinsbachian-
Toarcian) earliest post-rift marine source rock (Type II)
is postulated but remains unproven. Potential exists for
a Middle Jurassic Verrill (Callovian) source interval
(Type II-III), although due to limited data its extent and
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thickness is unknown. Better known is the Late Juras-
sic to Late Cretaceous Verrill Canyon Formation
assumed to be the source of most hydrocarbons
encountered so far (gas). Its main source intervals are
in the Tithonian (Type II-III), Valanginian (Type III),
and Aptian (Type III); terrigenous detritus from the
Sable Delta provides significant organic content. Note
that the source of the high gravity Cohasset-Panuke
oils, and those of other oil shows and discoveries (e.g.,
Penobscot field), remain unknown.
Reservoir distribution
Understanding the linkages between shelf sedi-
ment capture/delivery, the role of shelf margin deltas,
sea level, and slope processes is critical to detecting
reservoir rock distribution in deep and ultra-deep water
(Mosher et al. 2010). Thick Jurassic and Cretaceous
fluviodeltaic to shallow marine sands of the Mic Mac,
Missisauga, and Logan Canyon formations are com-
mon on the Scotian Shelf, and depending on location
have very high sand:shale ratios. Better ratios are found
in the middle and distal portions of the respective for-
mations. The deep water Scotian Slope demonstrates a
history of canyon and channel cut and fill and sediment
mass transport. Significantly, results from a recent
(2000-2004) phase of deep-water exploration (2D and
3D seismic) and drilling has confirmed the margin is a
by-pass zone, as coarse siliciclastics have been trans-
ported into the salt-dominated region down slope
(Kidston et al., 2007; Deptuck, 2010; 2011a; 2011b).
These processes link to relative sea level in combina-
tion with sediment volume, seismicity, and other
causative factors.
Trap
Although the Sable Delta represents an active
petroleum system associated with many significant gas
shows in the Upper Jurassic to Lower Cretaceous delta,
economic hydrocarbon accumulations have been lim-
ited (structural trap risk). Incised valleys, cut into shelf
deposits during sea level lowstands, are recognized on
3D data and indicate potential reservoirs when cali-
brated to well data. The dominant (and most
successful) trap styles are rollover anticlines in which
sand-shale ratios range from 15-30% and there is lim-
ited crestal faulting (Richards et al., 2008). Potential
exists for stratigraphic traps (but seal risk is high due to
an overall high net-to-gross section). Several traps
styles are set up by the movement of the underlying lat-
est Triassic-earliest Jurassic salt, particularly in deep
water, but only a few have been tested and most by a
single well: only one subsalt play has been drilled to-
date.
Seal
Within the Sable subbasin, variable scale (field
to regional) transgressive events developed “tongues”
of the Verrill Canyon Formation shales that provide
excellent seals to the reservoirs in the Sable Delta.
Discussion
Reservoir distribution
Shelf margin deltaic sequences are difficult to
correlate in the subsurface (Fig. 6). Delta lobe switch-
ing contributes to stratigraphic complexity. Numerous
permeability baffles and barriers create complex reser-
voir heterogeneities. For example, an extensive
network of non-marine channels and incised valleys
cut into deltaic and shelf deposits during the falling
stage and lowstand systems tracts at multiple strati-
graphic levels in the Sable Delta complex.
Progradation of the Sable Delta to the shelf edge is
constrained by localized accommodation controls from
differential mobilization of underlying salt. Shelf mar-
gin sediments can be trapped at the margin or may
contribute directly to downslope fans.
A significant issue in recent hydrocarbon explo-
ration in the deep water on the Scotian and Moroccan
margins is the detection of reservoir rock. Existing
models of deep-water sedimentation have underesti-
mated the links between shelf and slope sedimentation
and the roles of sea level, salt tectonism, and canyon
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formation as sediment transport pathways. Mass failure
and along-slope sediment transport processes are also
significant processes in passive continental margin
development. The consequence of these sedimentary
processes is the inherent complexities of shelf to slope
sedimentation patterns and movement of potential res-
ervoir rock to greater depths than previously
anticipated.
In the middle of the Cretaceous, rifting slowed or
ceased and wider continental shelves developed. Lat-
eral facies relationships along these shelf systems
could create stratigraphic pinch-outs to reservoir conti-
nuity in addition to faults that could act as transmissive
conduits or barriers, creating further reservoir compart-
mentalization. Condensed sections and transgressive
intervals of shales, diastems, hiatal surfaces, firm
grounds, and hard grounds (Ruffell and Wach, 1998)
formed that created potential significant barriers and
baffles to permeability and overall reservoir perfor-
mance. These surfaces were apparent in outcrops in the
Wessex and Channel basins, in the Jeanne d’Arc, and
even in the mid-Cretaceous oil sands of Western
Canada.
Tectonic influences on sedimentation, migration and maturation
Sinclair et al. (1994) and Shannon et al. (1995)
demonstrate there are tectonic influences on basin infill
and reservoir architecture. In the Wessex basin, there
are minor unconformities and non-sequences that are
due to eustatic changes and variable rates of local tec-
tonic subsidence. These subsequently have been
superseded in the Late Jurassic and Early Cretaceous
times by a major unconformity associated with late
Cimmerian tectonism, cutting the Mesozoic sequence
in southern England, the Lusitanian basin, Grand
Banks, and the Scotian basins. This period of extensive
erosion is referred to as the late Cimmerian unconfor-
mity. The late Cimmerian unconformity has formed in
an extensional setting by the combined effects of iso-
static footwall block uplift and a contemporaneous
eustatic lowering. This has produced a syn-extensional
or early post-extensional isostatic disequilibrium that
can be recognized throughout southern England. Only
in small areas of rapid basin subsidence are the effects
of the unconformity minimized, but the extent of this is
not clearly known.
The deposition of the Lower Greensand in south-
ern England marks the end of the late Cimmerian
event. Only in areas of rapid crustal subsidence are the
erosional effects minimized. These areas are the central
part of the Weald and Channel basins (Chadwick,
1986). The Lower Greensand thins and pinches out to
the north against the London platform and along the
western margins of the Wessex basin, overstepping
progressively older sediments. In turn, the Lower
Greensand is succeeded by the Gault and Upper Green-
sand. The Gault marks the second mid-Cretaceous
marine transgression. The dark grey mudstone of the
Gault oversteps the Lower Greensand to lie uncon-
formably on Lower Paleozoic strata of the London
platform. The Portsdown anticline and to a lesser
degree the Isle of Wight fault act as structural controls
to sedimentation and have restricted the influence of
the Boreal Sea from the north and the Tethys Sea to the
south and east. Abundant Upper Jurassic clasts in peb-
ble beds of the Lower Greensand Group suggest
contemporaneous erosion of shore lines along the mar-
gins of the Cretaceous depositional basin (Ruffell and
Wach, 1991). In the Lower Cretaceous, no sediments of
pre-Albian age are preserved north of the fault where
Albian Carstone sediments rest unconformably on
Jurassic.
The Late Cimmerian unconformity was com-
pared between the Jeanne d’Arc Basin of the Grand
Banks and the Outer Moray Firth in the North Sea by
Sinclair and Riley (1995). Early in the exploration of
the southern Grand Banks, dry wells in the basin were
attributed to an unproven source rock and breaching of
the traps at the basal Aptian (Avalon) unconformity
(Enachescu, 2006).
Basin accommodation space, shifting depocenters and inversion
In the outlier basins examined in this study, there
is evidence of shifting basin depocenters initially con-
trolled by local and regional tectonic events. Early rift
basins are filled with evaporite and red shales (Fig. 6).
As basins fill, eustatic controls overprint the tectonic
events, accommodation space is diminished, and depo-
sitional environments reflect slower rates of sediment
influx into a basin, often associated with erosion and
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denudation of surrounding highlands sourcing sedi-
ment into the basin. At the end of the basin cycle, the
studied basins have been inverted in response to Alpine
orogenic activity and compression along the eastern
Atlantic margin, particularly during the Oligocene
through Miocene. It is interesting that in the latest Cre-
taceous through early Cenozoic there is thermal
evidence of uplift along the Scotian margin (Grist et
al., 1995; Grist and Zentilli 2003).
Depocenters “shift” through the stratigraphic
succession in response to tectonic and eustatic controls
controlling accommodation space within the basins.
Identifying the primary and secondary controls within
a basin on sediment influx and distribution can help in
the prediction of sediment conduits and fairways for
the distribution of reservoir quality sediments.
During early Wessex Basin development, the rate
of Permo-Triassic sedimentation kept pace with base-
ment subsidence (Chadwick, 1986). Compaction
became a factor later in the basin development as load-
ing allowed sediment accommodation to exceed the
rate of basin subsidence. For example, fluvial condi-
tions were maintained during the deposition of the
Wealden Group in the beginning of the Lower Creta-
ceous, despite rapid basin subsidence because of
abundant sediment supply from the erosion of the prox-
imal massifs.
Lowering of sea level in the latest Jurassic to
Early Cretaceous created two distinct depocenters sep-
arated by the London-Brabant massif. The northern
basin was characterized by relatively slow subsidence
and low rates of sediment infill. In contrast, southern
England received significant sediment supply from the
erosion of nearby massifs, and coupled with rapid sub-
sidence rates, the basin was rapidly filled.
The Variscan fold belts across the Wessex basin
begin as thrust or reverse faults (Whittaker, 1985). The
depth to the top of the Variscan basement on the Isle of
Wight ranges from 1400-1600m north of the mono-
cline, to 2000m on the southwestern side, deepening to
2200m on the central and southeastern area of the
island. This deepening of accommodation space to the
island’s south-central area coincides with the thickest
deposit of Lower Greensand sediment in this region.
A half-graben may have formed during the
Permian (Chadwick, 1986) to late Cretaceous. The
Chalk facies shows evidence of reworking on the mar-
gins of the Central Downs and possible hard grounds
near the top of the strata, in the middle of the Central
Downs; combined with thinning of the Chalk strata
across the Central Downs, this suggests syntectonic
activity. Movement is concentrated during the Meso-
zoic with an interval of relative quiescence during the
mid to late Cretaceous. Mesozoic movement was fol-
lowed by inversion at the end of the Cretaceous
(Stoneley, 1982), which resulted in further develop-
ment of steeply folded strata as a result of movement
along pre-existing structures in the Paleozoic
basement.
The basins distributed along the conjugate mar-
gin of the Central Atlantic, although with similarities,
also demonstrate some marked differences; for exam-
ple the location of the (relatively younger) Atlas
Mountains along the northwest African coast compared
to the Appalachians. What is the significance of the
greater distance from North America to the Mid-Atlan-
tic Rift compared to the distance from Africa and the
breaks with the anomalies on both sides of the Atlan-
tic?
Evidence of active petroleum systems–Oil seeps on basin margins
Oil seeps within the Lusitanian and Wessex
basins are stratigraphically located in the upper Meso-
zoic, usually Cretaceous and Cenozoic strata. The
accumulations and active and paleo-oil seeps reflect
past and present petroleum systems that appear to have
migration pathways associated with faults bounding
the basin margins. Seeps are present in Cretaceous sed-
iments at Mupe Bay and in Cenozoic sediments at
Henigstbury Head. In the Lusitanian basin, there are
paleo- or active oil seeps at Vale Furado (Nazaré) and
Leiria.
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Conclusions
The key elements in producing effective petro-
leum systems (Fig. 6) in the Central Atlantic conjugate
margins are the presence of source rock and reservoir.
Trap formation and migration are less of a risk as active
tectonics occurred along the margin. The Wessex
(Channel) and Lusitanian basins are appropriate out-
crop analogs for basins along the Atlantic margin that
have relatively complex geological histories, multiple
sources of sediment into the basin, and restricted depo-
sitional settings to deeper marine settings. The
Lusitanian basin is a good analog for basins that transi-
tion from continental to deep basin marine settings.
There is more carbonate in the Lusitanian basin, per-
haps reflecting more southern latitudes of the basin
during the Mesozoic compared to the Wessex and
Channel basins. The Lusitanian basin provides analogs
for potential source rock facies, although maturity of
these is unlikely with the burial history of the basin less
than 500m.
Depocenters “shift” throughout the stratigraphic
succession in response to tectonic and eustatic controls
controlling accommodation space within these basins.
Identifying the primary and secondary controls within
a basin is dependent on sediment influx. Sediment con-
duits and fairways control the distribution of reservoir
quality sediments. Eustatic controls in the Portugal
basins appear to be less of a factor compared to other
basins along the margins, perhaps due to a greater tec-
tonic overprint.
What new exploration concepts and play types
are possible? A confirmed petroleum system is present
in the Flemish Pass basin on the Newfoundland Margin
which should decrease exploration risk in the adjacent
Orphan basin to the north. Exploration potential is
often contingent on the presence of source rock. We
can point to downdip deeper water reservoirs that may
be sourced from updip deltaic systems; e.g., the Sable
and Morocco delta systems. These deeper water reser-
voirs are often encased by excellent seal rocks and
within the fetch of condensed sequences that may form
potential source rocks.
Deciphering forcing functions, sediment path-
ways and depositional processes will improve
exploration models for passive clastic margins and sug-
gests that exploration must move to deeper water
where shelf-equivalent rocks are transported and
deposited. These constraints can be expected in similar
depositional settings in other margin basins. If there is
salt influence in the basin, new play concepts can be
generated with new trap configurations and the poten-
tial for trapping sediment.
There is a need to define basin-wide unconformi-
ties with greater precision. A number of unconformities
are not resolvable on seismic and may be interpreted as
one unconformity. These unmapped unconformities are
significant and mark the potential for downdip trans-
port of reservoir quality sediments in to the basin.
Seismic data can help predict reservoir but seldom aids
in defining reservoir quality. There is growing ten-
dency for plate reconstructions to rely solely on
subsurface data, particularly seismic and derivatives of
the seismic data used for modeling. John Dewey (1983)
reflected on his research and attributed many of the
concepts he developed on plate tectonics, to outcrop
studies he completed in Ireland and Nova Scotia. We
propose that we need to keep looking at the rocks to be
able to discern many of the complexities along the mar-
gins. The Wessex-Channel and Lusitanian basins
provide excellent outcrops to examine these and
develop new analysis of petroleum systems for petro-
leum exploration and development of fields and basins
of the Central Atlantic margin.
Acknowledgments
It is with great appreciation that we thank the fol-
lowing individuals for discussions throughout the years
both in the field and at conferences, particularly the
Conjugate Margins conferences: David E. Brown, Ian
Davison, Paul J. Post, Iain Sinclair, Ian Atkinson,
Michael Enachescu, Webster Mohriak, Bernardo Teix-
eira, Stephen Hesselbo, and Alastair Ruffell. David E
Brown provided valuable comments on the manuscript.
Carla Dickson, Trudy Lewis, Kristie McVicar, and Car-
los Wong assisted with the preparation of this paper.
We would like to thank Jim Pindell and Brian Horn as
conference organizers and particularly Norm Rosen
who each year continues to shepherd through a timely
conference confronting key issues facing the industry.
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Figure 1. Location of several sedimentary basins formed by the rifting and sea-floor spreading that began in the Late Triassic, leading to
the opening of the Atlantic Ocean (modified from Tankard and Balkwill, 1989; Decourt et al., 2000, among others).
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Figure 2. Petroleum systems chart of the Wessex basin (based on Underhill and Stoneley, 1998; Cox et al.,
1999; Hopson, 2005, among others).
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Figure 3. Petroleum systems chart of Central Portugal (based in Azerêdo et al., 2003; Rey et al., 2006; Witt,
1977, Pais et al., 2012, among others).
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Figure 4. Petroleum systems chart of the Grand Banks- Jeanne d'Arc basin (based on Grant and McAlpine,
1990; Sinclair et al., 1994; and Enachescu, 2006).
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Figure 5. Petroleum systems chart of the Scotian basin (after Wade and MacLean, 1990).
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Figure 6. Simplified lithostratigraphic schemes of the Scotian Shelf basins (after Wade and MacLean, 1990),
Jeanne d'Arc basin (Grant and McAlpine, 1990), Central Portugal (based in Azerêdo et al., 2003; Rey et al.,
2006; Witt, 1977, Pais et al., 2012, among others), and Wessex basin (based on Underhill and Stoneley, 1998;
Cox et al., 1999; Hopson, 2005, among others).
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... Powell and Snowdon, 1979) and reservoir attributes (e.g. Karim et al., 2011;Gould et al., 2012;Wach et al., 2014). The goals of this study were to determine and document the reservoir quality and facies of the Marmora, Sable, Cree, and Naskapi members of the Logan Canyon Formation using the integration of modern chemostratigraphic methods with a well-established sandstone classification scheme and porosity/permeability analysis. ...
... It is part of the Sable Sub-basin (~ 63,000 km 2 ) of the Scotian Basin (~ 300,000 km 2 ). The Logan Canyon Formation (Figure 1, Right) is part of the Cretaceous Nova Scotia Group and is a common reservoir rock interval occurring in the Scotian Basin (McIver, 1972;Wach et al., 2014). It comprises of a fining upward trend of thick, fluvial-deltaic to shallow marine sandstone (Wade and MacLean, 1990;Wach et al., 2014). ...
... The Logan Canyon Formation (Figure 1, Right) is part of the Cretaceous Nova Scotia Group and is a common reservoir rock interval occurring in the Scotian Basin (McIver, 1972;Wach et al., 2014). It comprises of a fining upward trend of thick, fluvial-deltaic to shallow marine sandstone (Wade and MacLean, 1990;Wach et al., 2014). It is subdivided into alternating shale dominated (Naskapi and Sable members) and sandstone dominated (Cree and Marmora members) intervals deposited over 25 million years from 121 M.A. to 96 M.A., forming reservoir seal pairs (Wade and MacLean, 1990;Smith et al., 2010). ...
Conference Paper
Full-text available
The Mid-Cretaceous Logan Canyon Formation has been proposed as a drilling target for hydrocarbons in the Sable Subbasin, offshore Nova Scotia. The thick Jurassic to Cretaceous fluvial-deltaic to shallow marine sands of the Logan Canyon and deeper Missisauga and Mic Mac formations form basin-wide reservoir rocks. Chemostratigraphic analysis can determine variations in elemental concentrations in reservoir and seal rocks. Results are integrated with a geochemical classification system, allowing for classification of the Logan Canyon Formation beyond just lithology type. High-resolution X-ray fluorescence measurements define five common and three uncommon facies for the Logan Canyon Formation. Handheld air permeameter measurements record the permeability of lithofacies and show variations in the reservoir both laterally and vertically. Borehole history reports contain laboratory-measured permeability and porosity values throughout the cored intervals. This data can be combined with the recently measured data to gauge reservoir quality further and confirm depositional settings. Results indicate the cored intervals have a variable reservoir quality, relating to different depositional settings within the fluvial-deltaic and shallow marine realms.
... The Logan Canyon Formation is composed of a thick fluvial-deltaic to shallow marine sandstone, which contains abundant paralic channel systems (Wach et al., 2014). The formation comprises alternating sandstone-dominated (Cree member) and shale-dominated (Naskapi and Sable members) sediments. ...
Article
Full-text available
Deltaic channels are good exploration targets and form potential hydrocarbon reservoirs. Generally, distributary sand-filled deltaic channels have high porosity and high permeability sandstones hence can form good quality reservoirs. We delineate deltaic channels within Cree Sand member of the Logan Canyon formation in the Penobscot field, offshore Nova Scotia, by devising a workflow that includes seismic data enhancement and attribute studies integrating coherence attributes, amplitude curvature and spectral decomposition attributes. An exhaustive seismic data conditioning improves considerably the signal-to-noise ratio in the conditioned seismic data (-4 dB at dominant frequency) compared to the input seismic (−22 dB at dominant frequency). We perform an integrated seismic attribute study which helps in effectively mapping the deltaic channel systems at different stratigraphic levels of the Cree Sand interval. We carry out a novel attribute analysis by comparing two types of volumetric curvature attributes namely, structural and amplitude curvatures. The structural curvature although depicting the fault patterns clearly, does not delineate the channels due to the absence of any flexure across the channel. Interestingly, the amplitude curvature attribute delineates different channel systems because of the amplitude variation across the channel edges. We identify narrower and thinner channels at the deeper stratigraphic level, while wider and thicker channels appear at the shallower level. Channel width varies from 870 m to 420 m and thickness from 110 m to 52 m from shallow to deeper level. Based on the integrated seismic attributes analysis, we identify varying channel width and thickness at different stratigraphic levels, that correlates to varying sea level.
... Formation. The Logan Canyon Formation is part of the Cretaceous-aged Nova 187Scotia Group and is a common reservoir rock interval occurring on the Scotian Shelf(McIver, 1881972;Wach et al., 2014). In the Sable Megamerge study area, sediment thickness ranges from 189 approximately 1,000 m to 2,000 m(Wade, 1991). ...
Preprint
Full-text available
The Mid-Cretaceous Logan Canyon Formation has been a proposed drilling target for hydrocarbons in the Sable Subbasin, offshore Nova Scotia. The thick Jurassic to Cretaceous fluvial-deltaic to shallow marine sands of the Logan Canyon Formation and deeper Missisauga and Mic Mac formations are basin-wide reservoir rocks. Modern chemostratigraphic analysis can determine variations in elemental concentrations within seal- and reservoir-quality rocks. These results are integrated with a geochemical classification system, allowing for the classification of the Logan Canyon Formation beyond lithology type. The use of high-resolution X-ray fluorescence measurements defines five common (Fe-sand, Fe-shale, litharenite, shale, and wacke) and three uncommon (sublitharenite, subarkose, and arkose) facies for the Logan Canyon Formation. Handheld air permeameter measurements demonstrate lateral and vertical permeability trends. Borehole history reports contain laboratory measured permeability and porosity values throughout the cored intervals, which also reveal a variable reservoir quality with baffles and barriers causing heterogeneity over short intervals. This data can be combined with the recently measured data to gauge reservoir quality further and confirm depositional settings. Results indicate the cored intervals have a variable reservoir quality, relating to different depositional settings within the fluvial-deltaic and shallow marine realms. These findings may also provide valuable information on other key reservoir attributes, such as pore networks, mineralogy, diagenesis, flow parameters, and rock mechanics. This application of a modern, handheld chemostratigraphic technique applied to the Logan Canyon Formation reveals a promising method for better understanding the complex facies patterns and heterogeneities that define this basin and its variable reservoir properties.
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Full-text available
Sandstone drill core and/or cuttings from six wells in the Gulf of St Lawrence and Cabot Strait have been analyzed using the apatite fission track (AFT) method. The AFT data indicate that most Maritimes Basin strata were heated to temperatures in excess of 100-150°C very soon after their deposition. The strata also attained significant vitrinite reflectant (Ro) levels early in the burial history. These findings imply the generation of hydrocarbons and coalbed methane in the early basin history (pre-250 Ma). Thermal model of the AFT data demonstrate that they are consistent with a history of exhumation of basin strata since late Permian time. -from Authors
Conference Paper
Full-text available
The Late Sinemurian ± Pliensbachian interval of the Lusitanian Basin is characterized by marly limestone deposits sometimes with organic-rich layers. The study of these levels in outcrops located in the northern part of the Lusitanian Basin using some geochemical parameters such as total organic carbon (TOC) and Rock-Eval pyrolysis, allowed the definition of its petroleum generative potential with high stratigraphic accuracy. There are two stratigraphic intervals particularly rich in organic matter, which are positioned in the Polvoeira Member of Água de Madeiros Formation and in the Marly limestones with organic-rich facies member of the Vale das Fontes Formation. These intervals are characterized by a high frequency of TOC values greater than 1% and/or several high values that can reach about 10%. The Rock-Eval pyrolysis parameter S2 is frequently above 10 mg HC/g rock, with highest value of 43.81 mg HC/g. The values of HI obtained for these intervals, very often larger than 150 mg HC/g TOC, show potential for generation of oil and gas-oil.
Technical Report
Full-text available
This report is a product of an ongoing long-term CNSOPB initiative aimed at improving the general understanding of the structural and stratigraphic evolution of the Scotian Margin using available 2D and 3D reflection seismic data-sets tied to wells. The report is intended to provide the reader with a higher fidelity view of the western half of the margin than is available in the Regional Geology section on the CNSOPB Call for Bids packages. Improved seismic imaging, afforded by the comparatively smaller size of salt bodies, the general absence of salt overhangs over wide areas, limited seafloor canyon incisions, and the generally thinner postrift stratigraphic interval, makes the western Scotian Margin a more attractive area to study deep-seated structural elements than areas to the east. These structural elements record the synrift to postrift evolution of the margin.
Article
An analysis of the surface geology and of surface and subsurface petroleum occurrences is used to unravel the complex history of the generation, migration and entrapment of oil in south Dorset. Lias shales began to generate oil in the Early Cretaceous. Some oil escaped up faults to the surface, generating the Mupe Bay palaeoseep, but much was trapped in the Bridport Sands. By the end of the Cretaceous, oil was migrating north across the Purbeck-Isle of Wight flexure. Inversion through the Tertiary sealed the faults, trapping petroleum in Wytch Farm and adjacent traps. Palaeogene uplift and cooling allowed the development of the fault-sealed Kimmerdige Bay underpressured system. Adjacent fault blocks to north and south may still be petroliferous at deeper levels.-from Authors
Article
The Lower Greensand (Aptian-Albian) around Calne, lies on Jurassic Lower Kimmeridge Clay (mid-Aulacostephanoides mutabilis Zone) and comprises a lower, relatively clean, fine to medium grained sand, overlain by iron-rich poorly-sorted, medium to coarse grained sandstone. The upper beds are identified as the Carstone, but the lower sands are lithologically different from the closely adjacent Lower Greensand occurrences on the margins of the Wessex Basin. They are here named the Calne Sands Formation of the Lower Greensand Group (equivalent to part of the Folkestone Beds Formation of SE England). The Calne Sands form an areally-restricted sequence with sand-grade sediment coarsening upwards and a concomitant increase in clay content. Palynological evidence indicates that they are referable to the Hypacanthoplites jacobi Zone. The age and sedimentary facies contrast with the nearby Seend Ironsand (Parahoplites nutfieldiensis Zone). Both occurrences however are interpreted as transgressive deposits infilling NW-SE palaeovalleys cut into Jurassic basement. -from Authors
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The Mesozoic and Tertiary structural and sedimentological evolution of the western Iberian margin can be related to the reactivation of structures within the Hercynian basement. Sedimentary basins probably formed by extensional collapse of the hanging walls of Hercynian thrust sheets. Within the Lusitanian basin, and also offshore, reactivation of north-northeast to south-southwest- and northeast to southwest-trending late Hercynian orogenic strike-slip faults in the basement strongly controlled basin geometry, facies distributions, the site of salt structures, and the location of extensional and compressional faults. The Mesozoic of the Lusitanian basin comprises four unconformity-bounded sequences which are related to extensional events in the evolution of the North Atlantic. Two inversion episodes resulted in the reversal of Mesozoic tensional/transtensional features and were related to the Pyrenean and Betic orogenies. -from Authors