Origin and timing of sand
injection, petroleum migration,
and diagenesis in Tertiary
reservoirs, south Viking
Graben, North Sea
R. Jonk, A. Hurst, D. Duranti, J. Parnell,
A. Mazzini, and A. E. Fallick
R. Jonk Department of Geology and Petroleum Geology, University of Aberdeen, AB24
3UE, Aberdeen, United Kingdom; present
address: ExxonMobil Exploration Company,
222 Benmar Drive GP8-448 Houston, Texas
77060; rene.jonk@exxonmobil.com
Rene Jonk received his M.Sc. degree in structural
geology from the Free University Amsterdam
(1999) and a Ph.D. from the University of
Aberdeen (2003) studying the origin and diagenesis of sand injectites. He is currently working
with ExxonMobil in Houston.
A. Hurst Department of Geology and Petroleum Geology, University of Aberdeen, AB24
3UE, Aberdeen, United Kingdom;
a.hurst@abdn.ac.uk
ABSTRACT
Petrographic, fluid-inclusion, and carbon and oxygen stable isotope
studies of Tertiary injectite reservoirs in the south Viking Graben of
the North Sea allow an understanding of the origin and timing of
sand injection, petroleum migration, and diagenesis. Injection from
shallowly (<400 m; <1300 ft) buried Paleocene and Eocene unconsolidated sandstones occurred at the end of the Eocene, probably in
response to earthquake activity. Liquid oil was already present in
the parent sands prior to injection and leaked from the injectites to
the seabed. Upward-migrating oil and basinal brines mixed with
downward-invading mixed meteoric-marine pore fluids in the injectites, causing extensive biodegradation of the oil. Biodegradation
of oil provided the driver for early carbonate cementation in injectites, causing diminished reservoir quality. However, early carbonate
cementation also sealed off the injectites as potential escape routes
for petroleum from the underlying parent sands. Oil (and gas) continued to migrate into the reservoir (parent) sands upon increased
burial, causing a mixing of high-API oil with the early charged,
extensively biodegraded low-API oil. The study of early diagenetic
imprints reveals the evolution of injectite reservoirs, which forms
the basis for understanding how to explore and develop them.
Andrew Hurst holds the chair of Production Geoscience at the University of Aberdeen, United
Kingdom. He has a B.S. degree from Aberdeen
and a Ph.D. from Reading (United Kingdom).
Prior to joining the academia in 1992, he worked
for more than 12 years in the international oil
and gas exploration and production industry. His
current research includes sand injectites, deepwater clastic systems, sediment composition, and
the nondestructive analysis of porous media.
D. Duranti Badley Ashton America, Houston, Texas; davideduranti@baai-houston.com
Davide Duranti received a Ph.D. in sedimentology
from the University of Bologna (Italy). He was
a research fellow for 4 years at the University of
Aberdeen (United Kingdom) and a geological consultant for various oil companies. His research
focused primarily on the injected sandstones associated with the deep-water reservoirs of the North
Sea. He recently joined Badley Ashton America.
J. Parnell Department of Geology and
Petroleum Geology, University of Aberdeen,
AB24 3UE, Aberdeen, United Kingdom;
j.parnell@abdn.ac.uk
INTRODUCTION
Outcrops of injected sandstones have been an intermittent subject
of interest for almost 200 yr (e.g., Murchison, 1827; Diller, 1890;
Newsome, 1903; Waterston, 1950; Winslow, 1983; Jolly et al., 1998).
Typically, field descriptions are given of what is considered to be a
Copyright #2005. The American Association of Petroleum Geologists. All rights reserved.
Manuscript received February 12, 2004; provisional acceptance June 24, 2004; revised manuscript
received October 15, 2004; final acceptance October 26, 2004.
DOI:10.1306/10260404020
AAPG Bulletin, v. 89, no. 3 (March 2005), pp. 329 –357
AUTHORS
329
John Parnell is a professor in the Department of
Geology and Petroleum Geology at the University
of Aberdeen, where he has taught since 1999. He
received his B.A. degree from the University of
Cambridge and his Ph.D. from Imperial College,
London. He is an editor of the journal Geofluids.
His research is focused on the composition,
evolution, and migration of fluids in sedimentary basins.
A. Mazzini Department of Geology and Petroleum Geology, University of Aberdeen, AB24
3UE, Aberdeen, United Kingdom;
a.mazzini@abdn.ac.uk
Adriano Mazzini received his M.Sc. degree in marine geology from the University of Genoa (1997)
and a Ph.D. from the University of Aberdeen (2004)
studying methane-related authigenic carbonates
and hydrocarbon-plumbing systems. He is currently a research assistant in the Department of
Geology and Petroleum Geology at the University
of Aberdeen.
A. E. Fallick Scottish Universities Environmental Research Center, G75 0QF, East Kilbride,
United Kingdom; T.Fallick@surrc.gla.ac.uk
Anthony E. Fallick graduated from Glasgow University with degrees in physics (B.Sc.) and chemistry (Ph.D.). He held postdoctoral positions in
geology and geography at McMaster University
(Ontario) and in mineralogy and petrology at
Cambridge University before moving in 1980
to East Kilbride. He is currently director of Scottish Universities Environmental Research Center
and professor of isotope geosciences in Glasgow
University.
ACKNOWLEDGEMENTS
An AAPG Grant-in-Aid donated in 2002 to the
first author assisted in performing fluid-inclusion
and carbon and oxygen stable isotope studies.
Kristine Holm (TotalFinaElf), Karen Martin (BP),
and Gerhard Templeton (Kerr-McGee) are
thanked for assisting with core examination
and sampling. Mads Huuse is thanked for his
scientific support throughout the duration of
the Injected Sands Project at the University
of Aberdeen (2000 – 2002). J. R. Boles, D. W.
Houseknecht, and D. A. Pivnik are thanked for
constructive reviews that helped improve the
manuscript.
DATASHARE 17
Datashare Tables 1–3 are accessible in an
electronic version on the AAPG Web site
as Datashare 17 at <www.aapg.org/datashare
/index.html > .
330
geological curiosity, sometimes offering explanations for their origin
(Murchison, 1827; Diller, 1890; Newsome, 1903; Waterston 1950)
and, more recently, adding paleostress studies of the geometries
of sandstone dikes, which aids in understanding the stress regime
at the time of dike formation (Huang, 1988; Boehm and Moore,
2002; Jonk et al., 2003). During the past decade, numerous descriptions have emerged of large-scale (hundreds of meters vertically and several square kilometers areally) sand injectite complexes
(all sandy facies associated with sand injection [see Duranti et al.,
2002] are hereafter referred to as sand injectites [after Hurst et al.,
2003]) associated with Tertiary petroleum reservoirs in the northern North Sea (Jenssen et al., 1993; Dixon et al., 1995; Lonergan
and Cartwright, 1999; Lonergan et al., 2000; Bergslien, 2002;
Duranti et al., 2002; Purvis et al., 2002; Hurst et al., 2003; Duranti
and Hurst, 2004; Huuse et al., 2004). These studies have largely
used seismic, core, and wire-line-log data, and although they assist
in the recognition of sand injectites, they shed little light on the
timing and genesis of sand injection.
Fluid overpressuring in a sand body is believed to be required
for sand injection to occur (Jolly and Lonergan, 2002; Duranti
and Hurst, 2004), and three mechanisms of fluid overpressuring
and subsequent sand injection are proposed:
disequilibrium compaction when pore-fluid expulsion from sediments upon burial is reduced because of rapid loading and/or
good seal integrity (Osborne and Swarbrick, 1997)
seismically induced liquefaction (Obermeier, 1996)
addition of overpressured (petroleum) fluids (Lonergan et al.,
2000)
Each of these mechanisms is invoked to varying extents to explain the sand injectites in the Tertiary petroleum reservoirs of the
northern North Sea (Lonergan et al., 2000; Jolly and Lonergan, 2002;
Duranti and Hurst, 2004; Huuse et al., 2004).
Because sand injectites form as a product of sand fluidization
and, once formed, continue to act as fluid conduits, study of their
diagenetic evolution should elucidate the relative timing of sand
injection, the involvement of petroleum, and the cementation history, which are vital for understanding sand injectite petroleum plays
(Figure 1). For example, injectites and underlying depositional sandstones (parent and parent sand body, hereafter used to describe the
depositional sand bodies from which sand injectites have emanated)
in Paleogene fields in the northern North Sea are strongly affected by
early diagenetic cements, particularly carbonate (Watson et al., 1995).
Hence, the presence or absence of petroleum fluid inclusions in diagenetic carbonate helps in understanding the relative timing of sand
injection and petroleum migration (Figure 1). Here, we present core
and diagenetic data from four petroleum accumulations in the south
Viking Graben of the northern North Sea (Figure 2) and attempt to
unravel the timing and origin of sand injection, petroleum migration,
and cementation in the Paleogene petroleum system.
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Figure 1. Cartoon illustrating two injectite reservoirs, with a different relative timing of sand injection,
petroleum migration, and
(carbonate) cementation.
Scenario A: Sand injection
occurs at shallow (a few
hundred meters) burial
depth, followed by localized carbonate cementation. After subsequent
burial (indicated with the
added dashed box of
mudstone in the last cartoon of scenario A), petroleum migration occurs.
Patches of pervasive carbonate cementation prevent the migration of
petroleum into some of
the injectites, whereas
some others, along with
the top part of the underlying parent sandstone,
form petroleum reservoirs. Scenario B: Petroleum migrates into the
unconsolidated sandstones at shallow (a few
hundred meters) burial
depth. Sand injection postdates petroleum migration and petroleum escapes
through those injectites
that reach the seabed
(dashed arrows). Some
petroleum may be trapped
in injected sandstones
that do not reach the
seabed. Late carbonate
cementation has no consequence as possible barriers to petroleum flow,
apart from diminishing
the reservoir quality in
some of the petroleumbearing injectites.
Jonk et al.
331
Figure 2. Left: location of the south Viking Graben to the east of the East Shetland platform. Dashed box indicates the location of detail on right.
Right: detail of dashed box in left diagram showing the outlines of the petroleum accumulations (gray) and the locations of cores from wells
studied (indicated in black). The license blocks are also indicated, along with the Norwegian–United Kingdom license boundary (dashed line).
THE TERTIARY PETROLEUM SYSTEM OF THE
SOUTH VIKING GRABEN
During the Cenozoic, the North Sea was an intracratonic sag basin developed over a series of failed Mesozoic rift structures (Ziegler, 1990). The studied petroleum
accumulations have reservoirs of Paleogene age located
in the south Viking Graben (Figure 2), which, at that
time, was situated in a marine basinal setting with water depths of 400 – 600 m (1300 – 2000 ft) (Joy, 1992).
Although the Tertiary section in the northern North
Sea is relatively unaffected by tectonic deformation, tectonic activity did have a major influence on sedimentation (Bowman, 1998). Rifting of the Greenland –
European plate in the early Paleocene caused the thermal
uplift of Scotland and the East Shetland platform (Bowman, 1998; Haaland et al., 2000; Ahmadi et al., 2003).
Clastic sediments derived from these uplifted areas
were deposited as deltaic and deep-water systems in
the south Viking Graben (Dixon et al., 1995); hence,
the majority of the Paleogene reservoirs are turbidite
systems sourced from the west.
332
The Paleogene of the northern North Sea is divided
into several basinwide sequences (Deegan and Scull,
1977; Mudge and Copestake, 1992; Bowman, 1998)
(Figure 3). Most of the examined core is from the lower
Eocene Balder and Frigg formations. The Balder Formation comprises laminated pyrite-bearing smectitic
mudstones interbedded with numerous, centimeterand decimeter-thick tuff beds, and thick (up to some
hundred meters), largely structureless, poorly cemented,
fine- to medium-grained sandstones. These thick sandstone units are mostly lobate in plan view and severely
mounded, with flanks as steep as 20j, in cross section
(Dixon et al., 1995; Huuse et al., 2004). The overlying
Frigg Formation consists of smectitic mudstones interbedded with thin (< 10-m [< 33-ft]-thick) sandstones.
METHODS
Core intervals containing injectites were examined,
after which samples were taken for diagenetic studies.
Broken surfaces of samples were first examined using
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Figure 3. Lithostratigraphy and nomenclature of
the northern North Sea
(modified after Mudge
and Copestake, 1992).
an ISI ABT-55 scanning electron microscope with a
Link analytical AN10155S electron-dispersive system
with a beam current of 30 – 70 mA and an acceleration
voltage between 15 and 25 kV. Following this first examination, samples were selected for thin sectioning.
Samples were mounted on 75 23-mm (3 1-in.)
glass slides and ground to a thickness of 30 mm. Samples
were prepared as uncovered polished sections and first
examined using a polarization microscope. Following
this, uncovered polished sections were examined for
different types of carbonates using a Cambridge CITL
Cold Cathodoluminescence 8200 mk3 with operating
beam current conditions of 200 – 300 mA and an acceleration voltage of 15 kV. Carbon-coated polished
sections were investigated for authigenic quartz and
feldspar using an Oxford Instruments Hot Cathodoluminescence detector on a Link analytical AN10155S
electron-dispersive system. Operating beam current
conditions were 30–70 mA with an acceleration voltage
of 25 kV. On the same system, at beam current conditions between 3 and 5 nA, the chemical composition
of diagenetic minerals was determined using a backscattered electron detector. Following petrographic studies, samples were selected for fluid-inclusion studies.
Samples for microthermometric analysis were prepared
as doubly polished wafers and examined using a Linkam
THM600 heating-freezing stage attached to a Nikon
Optiphot2-POL microscope. Finally, carbon and oxygen stable isotope analysis of authigenic carbonates
were carried out at the Scottish Universities Environmental Research Center. Samples of about 1 mg were
drilled from polished slabs with a spatial resolution
of about 1 mm. Sample powders were placed in a
temperature-controlled block at 70jC. Ultrapure helium was used to purge all atmospheric gases. Samples
were digested in 103% H3PO4 (Wachter and Hayes,
1985) and were left for 8 hr to react. Gas was extracted
on a AP2003 Gas Prep Interface by overpressurizing
Jonk et al.
333
with helium to 5 mbar. The resulting gas was analyzed
using an AP2003 triple-collector mass spectrometer with
a 1s reproducibility of ±0.1xfor both d13C and d18O
values. All data are reported as per-mil deviation from
the Vienna Peedee belemnite (V-PDB) standard unless
stated otherwise.
CORE DESCRIPTION
A total of 904 m (2965 ft) of core from 11 wells from
the 4 studied fields were examined (Figure 2; also
see Datashare Table 1 at AAPG’s Datashare Web site
[Datashare 17], www.aapg.org/datashare/index.html).
The A, B, and C fields are characterized by 10–100-m
(33–330-ft)-thick, largely structureless, unconsolidated
(parent) sands in the Balder Formation, overlain by up
to 100-m (330-ft)-thick sections of interbedded sandstone and mudstone, mainly in the upper part of the
Balder Formation and the overlying Frigg Formation.
Only the uppermost 10 m (33 ft) of a 50-m (160-ft)thick sandstone body enclosed in the lower part of the
Balder Formation were recovered from the D field.
This thick unit is overlain by generally centimeter-thick
sandstones encased in mudstones and abundant tuffs
and is underlain by a sand-rich (Hermod Member) Sele
Formation.
Four sandy facies, described in the subsequent section, are distinguished in the core: depositional sandstones, depositional sandstones affected by sand remobilization, injected sandstones, and injection breccias.
Depositional Sandstones
Surprisingly few sandstones show distinct primary depositional structures; however, a few thick (individual
beds typically on the order of 1–2 m [3.3–6.6 ft]), uncemented depositional sandstones occur in the Balder
intervals of the A, B, and C fields. These beds are characterized by parallel lamination, erosional bases, and
concordant tops and have mudstone clasts aligned
parallel to bedding (Figure 4A). These are believed to
be typical structures of sediment gravity flow deposits (Middleton and Hampton, 1973; Leeder, 1982).
Figure 4. Core examples of depositional sandstones. (A) Relatively
thick (1 – 2-m; 3.3 – 6.6-ft), uncemented, oil-bearing depositional
sandstones (dark) encased in mudstone (light) containing aligned
mudstone clasts (arrow 1), parallel
lamination (arrow 2), discordant
bases (arrow 3) and concordant
tops (arrow 4). Example is from
well 9. (B) Relatively thin (up-to20-cm [8-in.]), well-cemented (light)
depositional sandstones containing
parallel lamination (arrows). Example is from well 10.
334
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Thin (up to 20 cm [8 in.] thick) carbonate-cemented,
horizontally laminated sandstone units, which are
interpreted as depositional sandstones, are found in
the Balder section of the D field (Figure 4B).
Depositional Sandstones Affected by Sand Remobilization
The A, B, and C fields comprise 10–100-m (33–330-ft)thick sections of uncemented, structureless sandstones
that preserve no depositional structures. Their contacts
with the overlying mudstones, where preserved, are
commonly sharp and discordant. Thick sections of structureless sandstones in the lower Tertiary section of the
North Sea have been controversially attributed to the
deposition of sandy debris flows (Shanmugam et al.,
1995; Hiscott et al., 1997). The paucity of depositional
structures, the characteristics of the upper contacts, and
the association with injected sandstones in the overlying
mudstones support formation by severe postdepositional sand fluidization and remobilization, as inferred
for similar sandstones in the nearby Eocene Alba field
(Duranti and Hurst, 2004). The large-scale fluidization
and remobilization required for the upward injection
of significant amounts of sand is likely to have obliterated any depositional structures originally present
(Duranti and Hurst, 2004). Moreover, the steep-sided
mounded geometry of these sand bodies is likely to have
been, at least partially, produced by large-scale sand
remobilization (Dixon et al., 1995; Purvis et al., 2002;
Duranti and Hurst, 2004).
highly variable but tends to be more pervasive in thinner
sandstone dikes and is generally concentrated along the
margins of sand bodies (Figure 5C). Sandstone sills may
be difficult to discriminate from thin, depositional sandstones. However, the association of numerous, structureless, sharply bounded, thin concordant sandstones
with sandstone dikes favors an injected origin for most
of these sandstones because injectite complexes tend to
consist of an interconnected network of sandstone dikes
and sills (Parize, 2001; Jonk et al., 2003).
Injection Breccias
Up to 10-m (33-ft)-thick, sand-supported, mud-clast
breccias commonly occur associated with sandstone
dikes and sills in intervals that overlie thick, structureless sandstones. Individual units generally have discordant tops and bases, highly variable amounts and sizes
of mud clasts, and highly variable degrees of carbonate
cementation of the sandy matrix (Figure 6). Mud clasts
tend to be concentrated along the margins of sand bodies
(Figure 6), and carbonate cement tends to occur along
the margins of mud clasts (Figure 7). Mud clast size is
varied, ranging from a few millimeters to larger than
the core width (Figure 6). Sometimes, mud clasts form
a jigsaw texture, and clast rotation is sparse. We infer
that most mud clasts are unlikely to have been transported; rather, a depositional mudstone was pervasively
fractured and invaded by fluidized sand, thus creating
the brecciated appearance.
Injected Sandstones
PETROGRAPHY AND THE DIAGENETIC SEQUENCE
Injected sandstones comprise sandstone dikes (discordant to bedding) and sills (concordant to bedding), with
thicknesses ranging from subcentimeter to meter scale.
Numerous sandstone dikes occur in the up-to-100-m
(330-ft)-thick Balder and Frigg intervals of interbedded
sandstone and mudstone that overlie thick, structureless
sandstones (the parent) in the A, B, and C fields, whereas the Balder interval of the D field contains only a few
injected sandstones. Sandstone dikes display varied degrees of postinjection cementation, with uncemented,
oil-bearing sandstone dikes (Figure 5A) occurring in the
vicinity of pervasively carbonate-cemented sandstone
dikes (Figure 5B). Some uncemented sandstone dikes
display ptygmatic folding related to differential compaction (Figure 5A), whereas other carbonate-cemented
sandstone dikes display overlaps, which may have originated from brittle failure upon differential compaction
(Figure 5B). The distribution of carbonate cement is
A total of 53 samples were taken for petrographic
studies ( see Datashare Table 2 at AAPG’s Datashare
Web site [Datashare 17], www.aapg.org/datashare/index
.html). These include samples from injected sandstones,
injection breccias, and depositional sandstones.
Detrital Texture and Composition
Injected and depositional sandstones from all locations
have similar detrital composition, suggesting a common
source. They are generally subarkoses, with K-feldspar
dominating over plagioclase (plagioclase never exceeds
more than 20% of the total feldspar). Up to 2% muscovite may be present, along with minor glauconite, biotite, tourmaline, and zircon. The sandstones are fine to
medium grained, moderately to well sorted, and grains
are subangular to subrounded. The textural observations
Jonk et al.
335
Figure 5. Core examples of
injected sandstones. (A) Oilbearing (dark) ptygmatically
folded sandstone dike. Example is from well 6. (B) Wellcemented sandstone dike,
displaying brittle fracturing in
response to differential compaction (arrow). Example from
well 8. (C) Core images (left)
and interpretive drawing (right)
showing the distribution of
cement in sandstone dikes
encased in mudstone (bedding in mudstone indicated
with dashed lines). Examples
from well 9.
support the interpretation that the sandstones were
fed from well-sorted sediments at a shallow, wave- or
storm-dominated, sandy shelf delta (Dixon et al., 1995).
Factors Controlling the Present-Day Porosity
of the Sandstones
Figure 8 shows the relationship between cementation and compaction as the factors controlling the porosity evolution of the sandstones analyzed. A large
336
variation in the porosity evolution of individual samples is observed; however, one can roughly distinguish
two groups.
Group 1 consists of samples with intergranular volumes between 23 and 43% and cement volumes between 0 and 26%, where mechanical compaction is
the dominant factor causing porosity reduction but
where a component of cementation occurs as well. This
group includes both depositional and injected sandstones and the majority of the injection breccias. Group 2
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Figure 6. Core example
(top) and interpretive
drawing (bottom) of a
6-m (20-ft)-thick, oilbearing, sand-supported
injection breccia. The sand
is generally poorly cemented and oil bearing (giving
it a brownish color), although some patches are
pervasively carbonate
cemented (arrows). Mudstone clasts are angular
and display a range of
sizes from a few millimeters to tens of centimeters in width. Bedding
in mudstone is indicated
with dashed lines. Example is from well 9.
Jonk et al.
337
Figure 7. Core (left) and interpretive drawing (right) showing
that carbonate cement in injection breccias is concentrated in
the sand adjacent to mudstone
clasts. Example is from well 9.
consists of samples with intergranular volumes between 34 and 55% and cement volumes between 34
and 55%, where cementation is the dominant factor
causing porosity reduction. This group is dominated
by injected sandstones.
Diagenesis
Given the broadly similar diagenetic sequences for depositional sandstones, injected sandstones, and injection
breccias, we describe the general diagenetic sequence for
all sandstones together.
The General Diagenetic Sequence for All Sandstones
Ankerite is the earliest diagenetic cement and occurs
in modest amounts (never exceeding 20% of the total
rock volume) in samples from the A and C fields. Dolomite only occurs in limited amounts in samples from
well 2 in the A field, and its timing cannot be deduced
with certainty. Nonferroan calcite is volumetrically by
far the most important diagenetic mineral in all fields
338
and postdates ankerite (Figure 9A). It has a uniform, bright
luminescent character (Figure 9B) and makes up almost
100% of the cement volume and between 34 and 55% of
the total rock volume in the completely cemented sandstone belonging to group 2 (Figure 8). Pyrite is associated
with nonferroan calcite and occurs as small nodules (millimeter to centimeter size) in all four fields (Figure 9C, D).
Dull-luminescent ferroan calcite postdates nonferroan
calcite and only occurs in modest amounts in the
present-day water leg of the C and D fields (Figure 9E).
Authigenic quartz, K-feldspar, and kaolinite postdate all authigenic carbonates and occur only in samples
from group 1. K-feldspar occurs in trace amounts (never
exceeding 2% of the total cement volume) as nonluminescent overgrowths on detrital K-feldspar (Figure 9F)
and predates authigenic quartz and kaolinite. Quartz
and kaolinite always occur together (Figure 9G) and
appear to be (partly) coeval (Figure 9H). Partly dissolved
K-feldspar grains commonly occur in the vicinity of authigenic quartz and kaolinite. Minor occurrences of diagenetically late, mixed authigenic illite-smectite are present in some sandstones from the C and D fields.
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Figure 8. The relationship between compaction and cementations as the factors controlling
the porosity evolution of the
samples analyzed (method after
Houseknecht, 1987).
The Distribution of Authigenic Carbonates
Authigenic dolomite only occurs in modest amounts
in one sample from the A field, and thus, little can be
said about its distribution. Nonferroan calcite, ferroan
calcite, and ankerite occur in numerous samples from
all fields (although nonferroan calcite is, by far, the
most important volumetrically), and some trends are
noted.
Ankerite completely overgrows and/or replaces detrital smectitic mudstones and pervades only a few millimeters to centimeters into adjacent sand (Figure 9I).
Because ankerite solely occurs associated with host mudstones, it occurs along the margins of injected and depositional sandstones and along mudstone clasts in injection
breccias. As such, ankerite is more pervasive in injection
breccias, where abundant mudstone clasts are present
(Figure 10).
Calcite postdates ankerite and also nucleates along
the contacts between sandstones and detrital mudstone and mudstone clasts (Figure 7). In contrast to ankerite, calcite is more widely distributed, and relatively
thick (tens of centimeters), injected and depositional
sandstones are commonly pervasively calcite cemented.
Thicker (meter-scale) sand bodies remain relatively porous
away from their margins. Given the fact that only a few
injected sandstones reach meter-scale thickness compared
to the source and host depositional sandstones, the latter
provide more promising reservoir rocks at the present day.
Late ferroan-calcite only occurs in modest amounts
in the (present-day) water leg (Figure 10).
Jonk et al.
339
Figure 9. Micrographs illustrating the diagenetic sequence for both depositional sandstones and injectites. (A) Backscattered
electron image showing early disc-shaped ankerite (bright) enclosed by later nonferroan calcite (gray). Quartz grains are black.
Example is from sample A_4_6. (B) Cold cathodoluminescence micrograph showing nonferroan calcite constitutes a single, brightorange luminescent phase. Also note the high minus-cement porosities (around 50%). Example is from sample A_3_1. (C) Backscattered
electron image showing authigenic pyrite (bright) occurring as small concretions along the margin (dashed black line) between an
injected sandstone (left) and a host mudstone (right). Authigenic calcite (light gray) is associated with pyrite and encloses it. Example
is from sample C_9_3. (D) Micrograph taken in plane-polarized light showing porosity in blue, grains in white, and authigenic pyrite
in black. Note that authigenic quartz (white arrow) only occurs outside the pyrite concretion, suggesting it postdates authigenic pyrite.
Example from sample C_9_3. (E) Micrograph pair (plane polarized on left, corresponding image in cold cathodoluminescence on
right) showing bright luminescent nonferroan calcite postdated by dull luminescent ferroan calcite. Also note that the former contains
abundant petroleum inclusions (arrows). Example is from sample D_10_6.
340
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Figure 9. Continued. (F ) Micrograph pair (backscattered electron image left, hot cathodoluminescence image right) showing
K-feldspar grain (light grain) containing authigenic, nonluminescent K-feldspar overgrowths (arrows 1). Also note pore-filling
authigenic kaolinite postdating authigenic K-feldspar (arrow 2). Example from sample C_9_2. (G) Micrograph pair (backscattered
electron image left, hot cathodoluminescence image right) showing nonluminescent quartz overgrowths on quartz grains (arrows 1).
Also note pore-filling kaolinite (arrow 2) that always occurs in the vicinity of authigenic quartz. Example is from sample C_9_2. (H)
Scanning electron micrograph showing interlocking authigenic kaolinite and quartz, suggesting they are coeval. Example is from sample
C_9_2. (I) Backscattered electron image showing smectitic mudstone clasts almost entirely overgrown with white, disc-shaped
authigenic ankerite. Ankerite also occurs in more modest amounts in the surrounding sand and is postdated by nonferroan calcite
(light gray). Quartz grains are black, and K-feldspar grains are dark gray. Example is from sample D_1_3.
Jonk et al.
341
Figure 10. Cartoon illustrating the distribution of authigenic carbonates in Tertiary injectite reservoirs in the northern North Sea.
OWC = oil-water contact. See text for explanation.
DIAGENETIC CONDITIONS
DURING CEMENTATION
(type C), suggesting high API gravity, also occur, particularly in diagenetically late authigenic quartz (Table 1;
Figure 11B).
Fluid-Inclusion Studies
Fluid-Inclusion Petrography
Fluid-inclusion studies were performed on 13 samples
of depositional sandstones, injected sandstones, and
injection breccias (Table 1). Fluid inclusions were examined in authigenic ankerite, calcite, Fe-calcite, quartz
overgrowths, and in trails in detrital grains. In most
hosts, coexisting aqueous (type A) and petroleum inclusions (type B) occur; however, in Fe-calcite, only
aqueous fluid inclusions are found (Table 1). This is
consistent with the observation that Fe-calcite is found
only in the water leg. Petroleum inclusions are generally yellow fluorescent (Figure 11A), suggesting a low
to moderate API gravity (Lang and Gelfand, 1985),
although some blue fluorescent petroleum inclusions
342
Fluid-Inclusion Microthermometry
Fluid inclusions in quartz overgrowths were too small
to allow microthermometric measurements. Primary
fluid inclusions in authigenic carbonate consist predominantly of monophase liquid inclusions coexisting
with a population of two-phase inclusions with varied
liquid-to-vapor ratios. This suggests partial reequilibration of a population trapped at temperatures below 50jC (Goldstein, 2001). Salinities calculated from
64 final ice-melting temperatures (Bodnar, 1993) of
aqueous fluid inclusions (Table 1; Figure 12) show
the coexistence of a low-salinity (2.3 ± 0.8% NaCl
weight equivalent) aqueous fluid with a moderatesalinity (9.5 ± 1.4% NaCl weight equivalent) aqueous
fluid.
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Carbon and Oxygen Stable Isotope Studies
A total of 89 carbon and oxygen stable isotope pairs
were collected from pore-filling ankerite, calcite, and
Fe-calcite in injectites and depositional sandstones
(Figure 13A; Datashare Table 3, Datashare 17, at AAPG’s
Datashare Web site, www.aapg.org/datashare/index
.html/)). The data show a large spread with d18O values ranging from 12.62 to 0.73xand d13C values
ranging from 38.32 to + 13.07x. No clear differences are noted between the carbon and oxygen values for injected sandstones and depositional sandstones (Figure 13A); however, a clear division in d13C
values is noted for the three different types of carbonate cement (Figure 13B). d18O values show no
clear differences between subgroups; however, a frequency histogram of d18O values shows a skewed bimodal distribution with a dominance of d18O values
of about 10xand a smaller group with d18O values
of about 2x(Figure 13C).
DISCUSSION
Sand injectites formed in a subaqueous environment
provide a fascinating window into shallow crustal processes because they are formed by the release of overpressured fluids and then continue to act as preferential
conduits for fluid escape throughout burial. The diagenetic data presented here allow us to constrain both
how and when sand injection occurred.
The Timing of Sand Injection, Petroleum Migration,
and Calcite Cementation
The Timing of Sand Injection
A first estimate of the burial depth below the sea bed at
which sand injection occurred comes from the thickness
of strata penetrated by injectites above the parent (reservoir) sandstones, which is about 200 m (660 ft) for all
four investigated fields (Duranti et al., 2002; Jolly and
Lonergan, 2002; Huuse et al., 2004). Thus, if the injectites reached the contemporaneous sea bed (Huuse
et al., 2004), the minimum (postcompaction) burial
depth at which sand injection occurred is 200 m (660 ft).
However, at the present day, this thickness of 200 m
(660 ft) is observed at burial depths between 1400 and
2000 m (4600 and 6600 ft). If we consider the compaction
endured by the host strata (which are predominantly
smectitic mudstones), this thickness of 200 m (660 ft)
between 1400 to about 2000 m (4600 to 6600 ft) would
equate to approximately 400 m (4600 ft) from the sea bed
downward ( Velde, 1996) during injection. Thus, from
the present-day thickness of the interval containing
injectites, the minimum burial depth at which sand
injection occurred is about 400 m (4600 ft), which
equates to sand injection occurring at the end of the
Eocene (Figure 14).
Burial Depth of Calcite Cementation
Although calcite cementation obviously postdates sand
injection, the very high minus-cement porosities (most
samples between 45 and 55%; Figure 8) suggest calcite
cementation occurred prior to significant compaction.
Estimations of minus-cement porosities may be slight
overestimations of true precementation porosities because of displacive growth of carbonate (Tucker, 1981)
and grain dissolution during cementation (Burley and
Kantorowicz, 1986). However, only very minor grain
dissolution at the expense of calcite cementation is observed (at most 2–3% of the rock volume), and we have
no unequivocal evidence for displacive calcite growth;
thus, the minus-cement porosities between 45 and
55% are likely close to true precementation porosities. Using these values, along with a representative compaction curve for sandstones in the northern North Sea
(Figure 14), the depth range over which carbonate cementation commences is between about 0 and 800 m
(0 and 2600 ft) below the sea bed. Obviously, with a
minimum depth of 400 m (1300 ft) when sand injection occurred, carbonate cementation must have commenced between 400- and 800-m (1300- and 2600-ft)
burial, with the former being more likely than the latter
(because the former [400 m; 1300 ft] represents the
mean of all depth estimates from the minus-cement
porosity range). This implies that sand injection occurred
close to the minimum estimate of burial depth of 400 m
(1300 ft) (and reached the contemporaneous sea bed;
Huuse et al., 2004), and that carbonate cementation
commenced almost immediately (in geological time)
after sand injection occurred (Figure 14).
The Timing of Petroleum Migration
Direct evidence of the timing of petroleum migration
comes from fluid-inclusion studies. Primary petroleum
inclusions are found in ankerite and calcite cement in
pervasively cemented injectites and depositional sandstones alike (Table 1). Thus, petroleum migration occurred prior to ankerite and calcite cementation. Given
the short time span between sand injection and carbonate
cementation, it is plausible to suggest that petroleum
was present in the parent (reservoir) sandstones during
Jonk et al.
343
344
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
ankerite
Partly cemented
injection breccia
Pervasively cemented
injected sandstone
A_3_2
detrital
grains
A_1_1
calcite
detrital
grains
calcite
Host
Sample
P; isolated
yellow
N.A.
N.A.
yellow
yellow
blue
blue
blue
N.A.
N.A.
LB
LAVA
LA
LBVB
LB
LCVC
LC
LAVC
LAVA
LA
LAVA
N.A.
yellow-green
P; isolated
yellow
LBVB
LALB
P; isolated
N.A.
LA
yellow-green
P; isolated
N.A.
LAVA
LB
P; isolated
yellow
LB
P; isolated
P; isolated
P; isolated
S; intragranular
planes
S; intragranular
planes
S; intragranular
planes
S; intragranular
planes
P; isolated
and clustered
P; isolated
P; isolated
S; intragranular
planes
S; intragranular
planes
P; isolated
Occurrence
N.A.
Fluorescent
Color
LA
Contents
at Room
Temperature
Table 1. Results of Fluid Inclusion Studies*
3– 11
2 –4
3 –7
3– 10
2 –5
2 –7
2 –9
3– 12
2 –5
1 –4
1 –3
2 –8
3 –6
4– 12
2 –4
2 –6
2 –5
2 –7
Size Range
(mm)
ovoid to
elongate
irregular; negative
crystal shape
ovoid to
elongate
elongate
ovoid to
elongate
ovoid to
elongate
(sub-) negative
crystal shape
negative crystal
shape
(sub-) negative
crystal shape
negative crystal
shape
irregular; negative
crystal shape
irregular; negative
crystal shape
irregular
irregular; negative
crystal shape
irregular
irregular
irregular
elongate
Morphology
0.80 –0.95
1.00
1.00
1.00
0.80 –0.95
1.00
1.00
0.80 –0.95
0.80 –0.90
1.00
1.00
0.80 –0.90
1.00
0.80 –0.95
1.00
0.70 –0.95
1.00
1.00
Degree
of Fill
N.D.
N.A.
N.A.
N.D.
N.A.
N.A.
N.A.
N.D
N.A.
N.A.
0.9 to 6.5 (12)
N.D.
N.A.
N.A.
N.D.
N.D.
N.A.
N.D.
T m Range
(Number of
Measurements)
Jonk et al.
345
Pervasively cemented
injected sandstone
A_4_7
Partly cemented
injection breccia
A_4_5
calcite
detrital
grains
calcite
ankerite
detrital
grains
N.A.
yellow
LA
LB
N.A.
blue
LC
LA
yellow
LB
N.A.
S; intragranular
planes
S; intragranular
planes
S; intragranular
planes
P; isolated
and clustered
P; isolated and clustered
N.A.
N.A.
LAVA
LA
LAVA
P; isolated
yellow
LB
yellow
P; isolated
yellow
LBVB
LALB
P; isolated
P; isolated
yellow
LALB
P; isolated
yellow
P; isolated
and clustered
P; isolated
and clustered
P; isolated
and clustered
P; isolated
and clustered
S; intragranular
planes
S; intragranular
planes
S; intragranular
planes
S; intragranular
planes
P; isolated
LB
N.A.
yellow
LALB
LAVA
yellow
LB
N.A.
yellow
LBVB
LA
N.A.
LA
1– 4
3– 9
2– 8
2– 8
5–12
2– 5
2– 4
3– 8
1– 3
2 –5
2–10
3– 6
2– 4
4 –9
4 –12
1– 4
1– 4
2– 7
1– 3
negative crystal
shape
ovoid to
elongate
irregular
ovoid
ovoid to
elongate
(sub-) negative
crystal shape
negative crystal
shape
irregular
negative crystal
shape
negative crystal
shape
(sub-) negative
crystal shape
ovoid
elongate
elongate
Elongate
(sub-) negative
crystal shape
irregular
(sub-) negative
crystal shape
irregular
1.00
0.80 –0.90
1.00
1.00
1.00
1.00
1.00
0.85 –0.95
1.00
1.00
0.80 –0.90
1.00
1.00
0.75 –0.95
1.00
1.00
1.00
0.75 –0.90
1.00
N.D.
N.D.
N.A.
N.A.
N.D.
N.A.
N.A.
N.D.
0.4 to 1.5 (4)
N.A.
N.A.
N.A.
N.A.
N.D.
N.D.
N.A.
N.A.
N.A.
2.0 to 7.8 (12)
calcite
B_3
detrital
grains
quartz
overgrowth
detrital
grains
calcite
B_6
Poorly cemented
depositional sandstone
B_7
Poorly cemented
depositional sandstone
Poorly cemented
injected sandstone
quartz
overgrowth
Poorly cemented
injected sandstone
Host
detrital
grains
Sample
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
B_1
Table 1. Continued
346
N.A.
yellow
LA
LB
N.A.
yellow
LB
LA
N.A.
LA
blue
S; intragranular
planes
S; intragranular
planes
PS; intragranular
planes
PS; intragranular
planes
S; intragranular
planes
S; intragranular
planes
P; isolated
yellow
LBVB
LC
P; isolated
yellow
LB
N.A.
P; isolated
N.A.
LAVA
LA
P; isolated
N.A.
blue
LC
P; isolated
and clustered
S; intragranular
planes
S; intragranular
planes
PS; intragranular
planes
PS; intragranular
planes
P; isolated
Occurrence
LA
N.A.
yellow
LB
LA
N.A.
yellow
Fluorescent
Color
LA
LB
Contents
at Room
Temperature
1–7
1–3
1–3
1–3
1–3
1–3
1–3
1–3
1–3
1–3
1–3
1–3
1–3
1–3
1–3
2 –10
Size Range
(mm)
irregular
ovoid
ovoid
ovoid
ovoid
ovoid
irregular to
elongate
irregular to
elongate
irregular to
elongate
irregular to
elongate
ovoid
ovoid
ovoid
ovoid
(sub-) negative
crystal shape
ovoid
Morphology
1.00
1.00
1.00
1.00
1.00
1.00
1.00
0.75 –0.90
1.00
0.85 –0.95
1.00
1.00
1.00
1.00
1.00
1.00
Degree
of Fill
N.D.
N.A.
N.D.
N.A.
N.D.
N.A.
N.D.
N.A.
N.A.
N.D.
N.D.
N.A.
N.D.
N.A.
N.D.
N.A.
T m Range
(Number of
Measurements)
Jonk et al.
347
D_10_6
Partly cemented
injected sandstone
D_10_3
Pervasively cemented
injected sandstone
C_9_1
Pervasively cemented
injected sandstone
Poorly cemented
injected sandstone
C_8_1
B_8
calcite
quartz
overgrowth
calcite
calcite
calcite
quartz
overgrowth
P; isolated
P; isolated
P; isolated
P; isolated
P; isolated
P; isolated
P; isolated
PS; intragranular
planes
PS; intragranular
planes
P; isolated
P; isolated
orange-yellow
orange-yellow
N.A.
N.A.
orange
orange
N.A.
N.A.
yellow
N.A.
yellow
N.A.
N.A.
LBVB
LB
LAVA
LA
LBVB
LB
LAVA
LA
LBVB
LB
LAVA
LA
LA
P; isolated
N.A.
LA
P; isolated
P; isolated
P; isolated
N.A.
blue
LC
P; isolated
PS; intragranular
planes
PS; intragranular
planes
LAVA
yellow
N.A.
LB
LA
1– 3
3– 7
1– 3
1– 3
2– 8
2– 6
5–12
1– 3
1–10
1– 5
3– 8
2– 5
3–12
1– 4
3– 6
1– 3
1– 7
1– 3
(sub-) negative
crystal shape
(sub-) negative
crystal shape
ovoid
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
ovoid
irregular
irregular to
elongate
irregular to
elongate
1.00
0.85 – 0.95
1.00
1.00
0.80 – 0.95
1.00
0.80 – 0.95
1.00
0.90 – 0.95
1.00
0.85 – 0.95
1.00
0.90 – 0.95
1.00
0.85 – 0.95
1.00
1.00
1.00
0.4 to 8.0 (13)
N.D.
N.A.
N.D.
N.A.
0.3 to 9.1 (14)
N.D.
N.A.
N.A.
2.2 to 5.8 (3)
N.D.
N.A.
N.A.
1.0 to 5.6 (6)
N.D.
N.A.
N.A.
N.D.
N.A.
N.D.
N.D.
1.00
0.85 – 0.95
1.00
1– 4
P; isolated
N.A.
LA
3– 9
P; isolated
N.A.
Fe-calcite
LAVA
1– 3
P; isolated
yellow
LB
The Cause of Sand Injection
A full account of the mechanisms of sand injection is
beyond the scope of this paper. The development of
fluid overpressures in unconsolidated (parent) sand
bodies is generally accepted to occur prior to (hydraulic) fracturing of the sealing (mudstone) and fluidized
transport of grains into these fractures (sand injection)
to dissipate fluid pressures (Jolly and Lonergan, 2002;
Hurst et al., 2004; Huuse et al., 2004).
Because of the close timing between petroleum migration and sand injection, some workers have suggested
that overpressure may be generated by charge of overpressured, migrating petroleum in the unconsolidated
sands (Lonergan et al., 2000; Mazzini et al., 2003). In
particular, the presence of methane gas may cause overpressuring in the parent sandstones and breaching of the
seal (Huuse et al., 2004). However, during sand injection,
the Kimmeridgian source was not gas mature (Kubala
et al., 2003), and fluid-inclusion studies of early carbonate cements in depositional and injected sandstones do
not reveal the presence of methane. Furthermore, the
charge of oil into the Tertiary sandstones is thought to be
a buoyancy-driven process instead of a rapid charge of
overpressured petroleum (Kubala et al., 2003). The addition of petroleum may cause overpressuring in small,
laterally poorly connected sandstone bodies. However,
the parent sandstones exhibit good lateral connectivity at
the present day, which would have been even better at
the shallow burial depths when sand injection occurred,
allowing any pressure buildup at one location to be
evenly transferred throughout the whole body.
Another mechanism by which overpressure may
develop is through rapid burial of sand that is encased
in low-permeability lithologies (mudstones). Pore fluids
may not be expelled quickly enough to allow for normal
sediment compaction (Maltman, 1994; Osborne and
Sample
Pervasively cemented
depositional sandstone
Host
The Relation between Sand Injection, Petroleum Migration,
and Carbonate Cementation
Table 1. Continued
*Terminology after Van den Kerkhof and Hein (2001). L = liquid; V = vapor; P = primary; PS = pseudosecondary; S = secondary; N.A. = not applicable; N.D. = not determined.
N.A.
0.85 – 0.95
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
(sub-) negative
crystal shape
3– 7
P; isolated
yellow
Morphology
Occurrence
LBVB
T m Range
(Number of
Measurements)
Degree
of Fill
Size Range
(mm)
Fluorescent
Color
Contents
at Room
Temperature
the injection process and, thus, migrated through the injectites during their formation. The Upper Jurassic source
rock (Kimmeridge Clay) in this area reached oil maturity
at the end of the Paleocene and oil migrated into the
overlying Cretaceous and Tertiary strata throughout the
Eocene to the present day (Kubala et al., 2003). Given the
fact that sand injection occurred in the late Eocene
(Figure 14), oil was present and continued to migrate in
the early Eocene Age, shallowly buried sand bodies (being
buried to about 400 m [1300 ft] at the end of the Eocene)
when sand injection occurred (Figure 14).
348
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Figure 11. (A) Micrograph pair (plane polarized on left, corresponding image in fluorescent light on right) showing the occurrence
of bright fluorescent primary petroleum inclusions in authigenic calcite (arrows). Example is from sample A_4_7. (B) Micrograph pair
(plane polarized on left, corresponding image in fluorescent light on right) showing the occurrence of bright fluorescent petroleum
inclusions trapped along the quartz grain-quartz overgrowth boundary (arrows). Example is from sample B_6.
Figure 12. Frequency histogram
of fluid-inclusion salinities in authigenic calcite showing a bimodal
distribution.
Jonk et al.
349
Figure 13. (A) Crossplot of d13C – d18O
stable isotope pairs of authigenic carbonates. (B) Frequency histogram of
d13C values of the three chemically different types of authigenic carbonate.
Black is calcite, gray is Fe-calcite, and
white is ankerite. (C) Frequency histogram of d18O values of all authigenic
carbonates.
Swarbrick, 1997), and pore pressures may reach values
higher than the hydrostatic gradient. However, the sedimentation rates of the Eocene and overlying strata in
the northern North Sea are much lower (50–100 m/m.y.;
16–330 ft/m.y.; Jones et al., 2003) than the high sedimentation rates associated with this process (>600 m /m.y.;
> 2000 ft/m.y.; Mann and Mackenzie, 1990). Furthermore, at the shallow burial depth where sand injection
occurred (about 400 m [1300 ft]), the encasing mud350
stones would not be compacted sufficiently to be an
effective pressure seal (Deming, 1994).
The most commonly quoted cause for sand injection
is earthquake activity (Obermeier, 1996; Jolly and Lonergan, 2002). Seismic shaking can cause the development
of short-lived fluid overpressures and subsequent sand
remobilization through cyclic liquefaction (Obermeier,
1996). Sand injection occurred during a period when tectonic activity in relation to the North Atlantic breakup and
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Figure 14. Burial history and timing of sand injection, petroleum migration, and carbonate cementation illustrated in a porositydepth plot. Following deposition of the parent sandstones, the section has experienced steady, progressive burial throughout the
Tertiary and Quaternary (Kubala et al., 2003). The sandstone compaction curve used equates to $(z) = $0 e cz, where $(z) is the
porosity at depth z; $0 is the porosity at depth zero (the seabed; assumed to be 50%; Allen and Allen, 1990); c is a constant
(assumed to be 0.27 km 1; Allen and Allen, 1990); and z is the burial depth in kilometers.
Alpine collision caused basin inversion throughout northwest Europe (Huuse et al., 2004), and thus, it is conceivable that earthquake activity triggered sand injection.
Although we discard the hypothesis that petroleum charge directly caused sand injection, the fact
that buoyant petroleum fluids (partly) occupied the
pore space in the parent sand bodies during earthquake activity may have facilitated the creation of the
anomalously large-scale sand injectites observed.
The Origin of Carbonate Cement
Fluids Involved in Carbonate Cementation
Fluid-inclusion studies reveal three fluid types that
were present and trapped in the sandstones during carbonate cementation. Low to moderate API liquid petroleum inclusions are accompanied by two types of aqueous
fluid inclusions; a low-salinity (2.3 ± 0.8% NaCl weight
equivalent) aqueous fluid and a moderate-salinity (9.5 ±
1.4% NaCl weight equivalent) aqueous fluid (Table 1;
Figure 12). The former is untypically low for a marine
pore fluid (typical salinity of 3.5% NaCl wt. equiv.; Goldstein, 2001). Although it is possible that the salinity of
seawater has changed significantly through time (Goldstein, 2001), the values observed, along with the positive
skew toward values lower than about 2% in the salinity
distribution (Figure 12), is more likely caused by mixing of
marine water with meteoric water. This interpretation
substantiates independent work (Watson et al., 1995;
Stewart et al., 2000) that invoked a charge of meteoric
water from the nearby East Shetland platform into the
shallowly buried sediments to explain extremely depleted
d18O values of carbonate cements in Tertiary (depositional) sandstones.
The skewed bimodal distribution of d18O values
(Figure 13C) is unsatisfactorily explained by variations in precipitation temperature (Figure 15), and
mixing of two fluids with mean d18O compositions of
about 10 and 1xVienna standard mean ocean water
(V-SMOW) is invoked (Figure 15). These values correspond well with known compositions of Tertiary
meteoric water in Scotland (about 12xV-SMOW;
Fallick et al., 1985) and Tertiary marine water (about
1.2xV-SMOW; Shackleton and Kennett, 1975),
respectively.
The moderate-salinity aqueous fluid is typical of
basinal fluids (Warren and Smalley, 1994) and, together with the petroleum fluids, is thought to have
migrated from the oil-mature Kimmeridgian source
rock upward into the Tertiary parent sandstones. The
low-salinity aqueous fluid is thought to be the ambient
mixed marine-meteoric pore fluid present at the sea
bed and in the shallowly buried sediments. The injectites
created at shallow burial level form ideal pathways for
downward-invading mixed meteoric-marine fluids and
upward-migrating petroleum and basinal brines, hence,
their presence in early cements. Although at the present
day, the studied reservoirs are located far from exposed
Jonk et al.
351
Figure 15. Possible precipitation conditions for authigenic calcite derived from d18O data. The maximum and minimum precipitation
temperatures (38 and 10jC) are determined using the 400 –800-m (1300 – 2600-ft) depth range estimate of Figure 14, along with a
25 –35jC/km temperature gradient range (Barnard and Bastow, 1991) and a 0–10jC bottom-water temperature range (Shackleton
and Kennett, 1975). The total range of possible d18O pore-fluid compositions is given by the measured d18O range of authigenic
calcite, giving a range of possible d18O pore-fluid between 14 and + 2xV-SMOW. However, using the two mean values of the
bimodal distribution of d18O values of about 10 and 2x(Figure 13C) shows that the two fields of possible pore-fluid
compositions (fields 1 and 2, respectively) do not overlap, and thus, two different pore fluids are invoked; field 1 with a composition
between about 13 and 6xV-SMOW (mean about 10xV-SMOW) and field 2 with a composition between about 4 and
+ 2xV-SMOW (mean about 1x
).
land, during the late Paleogene, the northern North Sea
constituted a narrow, deep-marine basin bordered by uplifted, exposed land areas of Norway and the East Shetland platform in response to the North Atlantic rifting
(Huuse, 2002; Fyfe et al., 2003; Jones et al., 2003). In
addition, a pronounced eustatic lowering has been noted
at the Eocene–Oligocene transition, coinciding with the
timing of sand injection (Lear et al., 2000; Huuse, 2002).
This combined tectonoeustatic sea level fall would have
exposed most of the East Shetland platform west of the
bounding faults of the south Viking Graben, only kilometers away from the reservoirs studied (Figure 2). It is
thus conceivable that meteoric fluids flushed the shallowly buried injectites and their underlying parent sand bodies
during and shortly after injection.
Bicarbonate and Cation Sources for Carbonate Cement
In the shallow subsurface (less than 1-km [0.6-mi]
burial), two main reservoirs of bicarbonate are present;
marine bicarbonate (with a d13C 0xV-PDB) and bicarbonate produced from CO2 via bacterial degradation processes of organic matter, where four processes
352
are distinguished, all of which produce CO2 with characteristic d13C isotopic compositions (Irwin et al., 1977):
2CH2 O ! CH4 þ CO2 ðfermentation of organic
Þ
matter; d13 C of CO2 þ5 to þ 15x
CH2 O þ O2 ! H2 O þ CO2 ðoxidation of organic
Þ
matter; d13 C of CO2 30 to 20x
2
2CH2 O þ SO2
þ 2H2 O þ 2CO2
4 ! S
ðsulfate reduction with organic matter
Þ
oxidation; d13 C of CO2 30 to 20x
CH4 þ 2O2 ! 2H2 O þ CO2 ðoxidation of
Þ
methane; d13 C of CO2 80 to 40x
Whereas the fermentation and sulfate reduction
processes are anaerobic, the two oxidative reactions are
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
clearly enhanced by the presence of oxygen-rich meteoric waters, which, in this study, are interpreted to
have charged the injected and underlying depositional
sandstones during shallow (<800-m; <2600-ft) burial.
Distinct differences in the d13C isotopic signatures are
noted between the three types of carbonate (Figure 13).
Early ankerite is characterized by d13C values between
0.42 and + 12.36 with a mean of + 8.41 ± 4.52x
.
These values suggest a predominant source of carbon
derived from the bacterial fermentation of organic matter with a contribution of marine bicarbonate (Irwin
et al., 1977; Macaulay et al., 2000). Liquid petroleum
fluid inclusions in ankerite cement show that liquid
petroleum was present during the precipitation of ankerite and, as such, provides the most obvious source of
organic matter (given that the host Paleogene mudstones are not enriched in unoxidized organic matter).
Early fermentation of organic matter and the introduction of meteoric waters in the shallowly buried injected
sandstones and underlying (parent) depositional sandstones from the nearby East Shetland platform have been
invoked by others (Watson et al., 1995; Macaulay et al.,
2000; Stewart et al., 2000).
The observation of ankerite overgrowing and occurring in the vicinity of host smectitic mudstone clasts
(Figure 9I) suggests that cations may be partly derived
from these mudstones. Smectite occurs abundantly in
the host mudstones and tuffs and formed through the
alteration of volcanic glass (Watson, 1993), a reaction
that releases cations and, as such, is commonly accompanied by carbonate cementation (Andreozzi et al.,
1997; Buck and Bates, 1999). We do note, however,
that sand injectites act as foci for fluid flow during
burial and may transmit considerable pore volumes of
fluid per unit volume of sandstone, and thus, external
sourcing of cations may also be a factor in sand injectites, although unrealistic fluid fluxes are required to
account for the full volume of observed carbonates
(Walderhaug and Bjørkum, 1998).
Exhaustion of suitable hydrocarbons for fermentation leads to a (rapid) change in the way CO2 is
generated (Irwin et al., 1977), and bacterial oxidation
and sulfate reduction take over. Instead of ankerite,
calcite precipitates with d13C values of about 25x
,
typical of carbon derived through oxidation and/or
sulfate reduction of the petroleum. Some of the more
depleted d13C values (between about 40 and 30x
;
Datashare Table 3, Datashare 17, at AAPG’s Datashare
Web site, www.aapg.org/datashare/index.html) are likely caused by minor carbon derived from the oxidation of
methane produced during the fermentation process. The
skew toward d13C values around 0x(Figure 13B) is
caused by additional sourcing from marine-derived
bicarbonate. The precipitated carbonate is low in Fe2 + ,
because this component is taken up in associated pyrite
precipitating during sulfate reduction.
Fe-calcite is the last diagenetic carbonate to precipitate. It occurs in minor amounts in the present-day
water leg only, and d13C values of about 0xsuggest an
ultimately marine bicarbonate source, probably derived directly from the mixed meteoric-marine-basinal
pore fluid.
The Evolution of the Tertiary Reservoirs in
the Northern North Sea
Figure 16 shows schematically the evolution of the
reservoirs studied, incorporating all diagenetic data. Oil
migration from the Kimmeridgian source commenced in
the late Paleocene and entered the shallowly buried Paleocene and Eocene strata throughout the Eocene along the
graben-bounding faults (Kubala et al., 2003). Sand injection occurred near the end of the Eocene, probably in
response to earthquake activity, with the buoyant petroleum pore fluids facilitating large-scale injection. Oil
migrated upward through the injectites that probably
reached the contemporaneous sea bed (Huuse et al.,
2004). The injectites form conduits at shallow burial
through which mixed marine-meteoric fluids migrate
downward from the nearby exposed East Shetland platform. In the presence of these aqueous fluids, bacteria
ferment some of the oil, and CO2 released from this
reaction is incorporated in minor early ankerite with
d13C of about +10x
. With continued upward migration of oil and downward migration of marine-meteoric
fluids and exhaustion of hydrocarbons suitable for fermentation, a reversal to oxidation and/or sulfate reduction occurs (Irwin et al., 1977). The oil is being
extensively biodegraded, and CO2 released through
these reactions is incorporated in extensively occurring calcite with d13C of about 25x
. Coeval pyrite
precipitates through sulfate reduction. Calcite cementation is locally pervasive and may form barriers
that halt continued petroleum migration through some
of the injectites. Continued burial halts the downward
invasion of low-salinity aqueous fluids, and oil and gas
migrating throughout the Pliocene and Quaternary is
not degraded, hence, the presence of both low- and
high-API oils in the fields (Figure 16) and the presence
of high-API fluid inclusions in late authigenic quartz
(Table 1) in particular. Silicate diagenesis (K-feldspar
Jonk et al.
353
354
Origin and Timing of Sand Injection, Petroleum Migration, and Diagenesis, South Viking Graben
Figure 16. Cartoon illustrating the evolution of the Tertiary injectite reservoirs in the south Viking Graben as deduced from diagenetic studies. See text for explanation.
dissolution, quartz cementation, and clay mineral cementation) takes over at increased burial, with kaolinite
and quartz cementation related to K-feldspar dissolution
(Worden and Morad, 2000) and late onset of illitization
of smectite also being accompanied by further quartz
cementation (Worden and Morad, 2003).
CONCLUSIONS
Being able to constrain the timing of sand injection,
petroleum migration, and pervasive (carbonate) cementation is a major aspect of understanding injectite petroleum plays in the northern North Sea and probably
elsewhere in the world. In this case, we have shown that
petroleum migration occurred prior to sand injection
and continued to migrate following the injection process. As such, petroleum has been lost to the contemporaneous sea bed, and petroleum trapped at very
shallow (0- to about 500-m; 0- to about 1600-ft)
burial depths was extensively biodegraded by invading low-salinity (mixed meteoric-marine) fluids. Apart
from diminishing the quality of oil, this process had
another important consequence from a petroleum exploration point of view: it provided an excellent bicarbonate source for pervasive, early carbonate cementation.
In fact, it was previously suggested that in those injectite
reservoirs where oil migration occurred more or less coeval with sand injection, about 30% of the pore space in
sandstones was filled with carbonate cement, whereas
those where oil emplacement was later only about 4% of
the pore space was occupied by carbonate cements
(Macaulay et al., 2000). In the fields studied here, this
order of cementation is confirmed in depositional (parent) sandstones, with the percentage of pore space
occupied by carbonate cement in injectites even higher,
as much as 50–60% in some of the fields studied
(Figure 8). From this point of view, it is important to
understand the distribution and magnitude of carbonate cementation in injectite reservoirs where biodegradation of shallowly migrated oil may contribute substantial amounts of bicarbonate to the aqueous pore fluid
and thus may be the driver of carbonate cementation.
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