Geo-Mar Lett (2003) 23: 323–339
DOI 10.1007/s00367-003-0145-y
O R I GI N A L
Adriano Mazzini Æ D. Duranti Æ R. Jonk Æ J. Parnell
B. T. Cronin Æ A. Hurst Æ M. Quine
Palaeo-carbonate seep structures above an oil reservoir,
Gryphon Field, Tertiary, North Sea
Received: 28 January 2003 / Accepted: 29 May 2003 / Published online: 23 October 2003
Springer-Verlag 2003
Abstract Petrographic and geochemical analyses performed on a North Sea core from the Gryphon Field reveal the presence of palaeo-degassing features surrounded
by injected sandstones in the Eocene interval. The injected
sandstones are oil-stained and poorly cemented by carbonate and quartz. 18O isotope analyses indicate that
carbonate cementation occurred during shallow burial
(likely less than about 300 m). Depleted 13C (around
)30& V-PDB) carbonate cement suggests that bicarbonate was derived from the microbial oxidation of oil
and gas. Late quartz overgrowths enclose oil present in the
injected units. The tubular degassing conduits are composed of zoned cements and have d18O and d13C isotope
values similar to the injected sandstones, indicating that
oil and gas seepage induced the precipitation of authigenic
carbonate in the shallow subsurface. Oil inclusions in
inter- and intra-crystal cement sites in both injected
sandstones and degassing conduits indicate that oil seepage was an ongoing feature at shallow burial. A proposed
model involves oil and gas seepage and the formation of
the degassing conduits, followed by a sand injection
phase. It seems likely that oil and gas continued to
leak towards the seabed by exploiting the network of
permeable injected sandstones and the horizons of porous
degassing features.
A. Mazzini (&) Æ D. Duranti Æ R. Jonk Æ J. Parnell
B. T. Cronin Æ A. Hurst
Department of Geology and Petroleum Geology,
University of Aberdeen, Meston Building,
Kings College, Aberdeen, AB24 3UE UK
E-mail: a.mazzini@abdn.ac.uk
Tel.: +44-1224-273435
Fax: +44-1224-272785
M. Quine
Kerr McGee North Sea Limited,
Ninian House, Crawpeel Rd.,
Aberdeen, AB12 3LG, UK
Introduction
Focussed fluid migration in the shallow crust is a widespread phenomenon which is increasingly gaining attention but is still not fully understood. Gas escape from
buried units is one of the most obvious expressions of fluid
migration. Fluids can follow different pathways, generating diverse geological structures and phenomena. The
occurrence of fluid and gas seepage is manifested on the
seafloor by the presence of pockmarks, diapirs, deepwater coral reefs and mud volcanoes (Hovland and Judd
1988). A diversity of depositional and tectonic settings has
been recognised as preferential locations for seeping and
venting activity. Gas seepage, especially methane (cold
seeps), is observed in offshore areas of active continental
margins (Le Pichon et al. 1990; Sakai et al. 1992; Corselli
and Basso 1996; Bohrmann et al. 1998), and regions of
rapid sedimentation at passive continental margins
(Hovland et al. 1987; Hovland 1992; Paull et al. 1992;
Roberts and Aharon 1994; Vogt et al. 1997). This phenomenon is frequently associated with the growth of
distinct chemosynthetic communities (Sibuet and Olu
1998) and, more commonly, with the occurrence of authigenic carbonate mineralisation as a consequence of the
microbially mediated oxidation of methane (Ritger et al.
1987; Boetius et al. 2000). Carbonate deposits can vary in
size from mm-scale carbonate micro-slabs (and mineralised veins) to extensive deposits of several hundreds
meters in scale (Kelly et al. 1995; Aloisi et al. 2000).
Several of these features can occur on the seafloor
above petroleum reservoirs. Examples of gas, and
occasionally oil, leaking from reservoirs include seeps
from the Gulf of Mexico (Sassen et al. 1993), the southeastern Mediterranean (Coleman and Ballard 2001), the
North Sea (e.g. UK Block 15/25, Judd et al. 1994) and
the southern and eastern Skagerrak (Hovland 1991).
Even at depth, fluid escape from hydrocarbon fields is
one of the most frequent phenomena revealed by subsurface investigation tools in hydrocarbon exploration
and production. Large-scale gas leakage is commonly
324
observed on seismic data as acoustic anomalies showing
vertical transparent areas and masked reflectors above
reservoirs (Hovland and Judd 1988; Heggland 1998).
Injected sandstones are frequently observed above the
Palaeogene reservoirs of the northern North Sea (Jenssen et al. 1993; Dixon et al. 1995; Lonergan et al. 2000).
They are increasingly recognised in new petroleum
provinces, such as the Angolan offshore and the
Norwegian Sea (Møller et al. 2001).
All the documented evidence of gas escape from
hydrocarbon reservoirs are present-day features. Ancient gas escape products above hydrocarbon reservoirs
are virtually undocumented. This paper focuses on carbonate seep features and injected sandstones forming
during hydrocarbon leakage above the Palaeogene reservoir of the Gryphon Oil Field (northern North Sea).
Geological background
The Gryphon Oil Field is located in Block 9/18b in the
southern part of the Beryl Embayment of the South
Viking Graben (northern North Sea; Fig. 1A). After the
major Mid–Late Jurassic rifting event, the North Sea
basin went through a phase of relative tectonic quiescence
in the Late Cretaceous and became starved of sediments.
During the Early Tertiary the thermal uplift of the East
Shetland Platform renewed clastic supply and turned the
South Viking Graben into a major depocentre (Newman
et al. 1993; Dixon et al. 1995). Large-scale deltas and
shelfal systems, with associated deep-water facies, formed
south-eastwards of the uplifted areas. In the Early Palaeocene, deep-water sedimentation consisted of extensive,
sheet-like units of sand with subordinate mud, which are
believed to represent large-scale submarine fans (Den
Hartog Jager et al. 1993; Bowman 1998). Smaller-scale
sand-prone bodies enclosed by mud gradually became
more common in the Late Paleocene and Eocene (Anderton 1997). These bodies are mainly interpreted as deepwater channel fills (Newton and Flanagan 1993) or as
accumulations of large-scale failures of deltaic and nearshore sediments. The Balder Sandstones (Fig. 2, Upper
Palaeocene and Lower Eocene) in the South Viking
Graben represent this transition to more isolated sand
bodies. In the Bruce-Beryl Embayment the deep-water
sandstone bodies of the Balder Formation were deposited
at or near the toe of a complex delta system, represented
by the Dornoch Formation (Upper Palaeocene, Timbrell
1993). They are interpreted as the deposits of large-scale
retrogressive slides and slumping on the delta front, which
were caused by the high sedimentation rates and steep
profiles (Newman et al. 1993; Dixon et al. 1995). The wellsorted, fine grain size and homogeneous nature of these
deep-water deposits suggest resedimentation from a
wave-dominated shelf delta. The forced anticline which
formed above the Crawford Ridge, a relict Mesozoic
structural relief, acted as a barrier and ponded the mass
flows coming from the delta (Fig. 1A, Newman et al.
1993; Purvis et al. 2002). Delta front failure and resedi-
Fig. 1 A Geological setting of the Gryphon Field area. Dark
shading Main structural features, dotted areas main oil fields, light
shading highs, non-shaded areas basinal areas. B Outline of the
Gryphon Field and location of the main wells and the studied cored
well (9/18b-13). Location map in inset. Redrawn and modified after
Newman et al. (1993)
mentation occurred during a second-order rise in sea level
(Dixon et al. 1995). Regional tectonic events, related to
the East Shetland Platform uplift, controlled the sea level
and formed the Early Palaeogene unconformities of the
North Sea (Jones and Milton 1994; White and Lovell
1997).
In the same period, extensive units of volcaniclastic
material were deposited in this deep-water setting
and formed the Late Palaeocene Balder Tuffs. Both
the volcanic activity and the Early Tertiary uplift of the
East Shetland Platform occurred in response to the
325
well preserved. An almost complete record of the Frigg
Formation and a large part of the Balder Formation are
preserved in this core (Fig. 3A). The lowermost part of
the Balder Formation, approximately 100 feet, was not
cored. The occurrence of thick sandstone units in the
lowermost uncored part of this formation can be inferred from wireline log interpretation and inspection of
drilling cuttings (Fig. 3B). Three main lithotypes are
preserved in the cored record: tuffs, sandstones and
mudstones.
Tuffs
This lithotype is formed by thin, white to light green
beds of fine-grained volcaniclastic material (Hatton et al.
1992; Newman et al. 1993). The beds have a sharp base
and gradational top. They may display normal grading
and, rarely, parallel or low-angle lamination. These beds
of volcaniclastic material characterise several distinct
intervals of the Balder Formation. In total they form
approximately 5% of the studied cored record.
These tuffs were mainly deposited by sediment gravity flows, as can be inferred by the internal structures
and bedding surfaces characteristics. The volcanic
material was redeposited in the deep-water environment
from temporary offshore storage areas. Similar units of
volcaniclastic material are very common in most of the
cored Palaeocene sequences of the northern North Sea.
Sandstones
Fig. 2 Generalised stratigraphic column of the South Viking
Graben with inset showing the lithostratigraphy of the Gryphon
Field (redrawn and modified after Joy 1997)
opening of the North Atlantic Ocean (Haaland et al.
2000).
These base-of-slope deep-water sandstone bodies form
the main reservoir of the Gryphon Oil Field, which extends over an area of approximately 14 km2 (3,500 acres)
in UK Block 9/18b (Fig. 1). The field contains low API oil
(21.51) and has a large gas cap. In the Gryphon Field, the
sandstone bodies are up to 120 m thick, with steep sides
(up to 18). The sandstones are clean, fine to medium
grained, poorly cemented, generally highly porous (30–
33%) and mainly structureless. Over 2,000 feet of core has
been recovered from 11 wells in the field. Injected sandstone units at core and seismic scale occur both in the
Balder Formation and in the overlying Frigg Formation
(Purvis et al. 2002). The examined section was cored in
well 9/18b-13, which is located at the southern border of
the main Gryphon Field (Fig. 1B).
Core description
The examined vertical cored section is nearly 500 feet
long. Cores are approximately 6 inches in diameter and
Sandstone units form approximately 30% of the cored
interval. Sandstones are arkosic and medium to fine
grained. Two main sandstone lithofacies are recognised
in this core: stratified sandstones and injected sandstones.
Stratified sandstones
This lithofacies is composed of sandstones which preserve the original depositional structures. Only one thick
bedset of amalgamated, fine-grained stratified sandstones is present in this core (core depth 5,597–5,625 ft;
Fig. 3). Individual beds are up to 6 ft thick with parallel
lamination and erosional bases. The primary stratification is deformed and obliterated by numerous pore-fluid
escape structures (cm-scale pillars) in the uppermost part
of this bedset (core depth 5,597–5,604 ft). The upper
contact between this sandstone package and the overlying mudstone is sharp and discordant with respect to
the mudstone bedding.
This bedset of stratified sandstones is interpreted as
having been deposited by sediment gravity flows, in
particular turbidity currents. The upper part of the
bedset was affected by intense fluidisation, as shown by
the numerous pore-fluid escape structures. Fluidisation
was associated with sand remobilisation which produced
326
327
b
Fig. 3. A Stratigraphic subdivision of cored and studied interval
from well 9/18b-13. B Stratigraphic log of well 9/18b-13, including
water, oil and gas columns
the discordant bedset top and may have produced the
injected sandstone units of the overlying sequence.
Injected sandstones
Numerous sandstone dykes and sills occur in this core.
Dykes are commonly thin (few centimetres to 1 m), with
margins discordant to the bedding of the adjacent
mudstones (Fig. 4A). Margins are very sharp, indented
and frequently associated with deformation in the
encasing mudstones. Sills are more difficult to recognise
because of their bedding-concordant relations, but their
margins have the same characteristics. These injected
units reach, in one case, up to 20 ft in vertical thickness
(core depth 5,735–5,758 ft, Fig. 4B). The total of the
sandstone units in the cored part of the Frigg Formation
consists of this lithofacies. These injected units are
interpreted as having been produced by fluidisation,
sand remobilisation and injection during burial. Injected
sand units are common in the Palaeogene deep-water
sequence of the northern North Sea (Dixon et al. 1995;
Lonergan et al. 2000; Duranti et al. 2002).
The cored mudstones were mainly deposited as
hemipelagites with some possible contributions from
very fine-grained, low-density turbidity currents. The
origin of the carbonate features is discussed below.
Materials and methods
A collection of polished thin sections was prepared
from stratified sandstones, injected sandstones, tubular
features, nodules and concretions sampled from the
Gryphon core 9/18b-13 (Table 1). Polished slabs and
thin sections were studied using standard petrographic
and cathodoluminescence techniques. Cathodoluminescence (CL) was conducted using the Citl Cold Cathode
Luminescence 8200 mk3, attached to a Nikon OptiphotPOL microscope. Fluorescing petroleum inclusions were
Mudstones
Homogeneous or weakly laminated mudstones form the
most abundant lithotype (approximately 65%) in the
cored record from this well. Mudstones are dark grey
and weakly bioturbated in the Balder Formation; they
are lighter, grey-green and locally strongly bioturbated
in the Frigg Formation.
Various kinds of diagenetic carbonate features occur
throughout the cored mudstones and are locally very
abundant. Numerous white, tubular carbonate features,
up to 3 cm in diameter, occur in the Frigg Formation
(Figs. 3A and 4A). The tubular features tend to be
concentrated in discrete, m-thick levels at, for example,
5,462–5,474 and 5,482–5,486 ft (core depth) and they are
often associated with injected sandstones (Fig. 3).
Crosscutting relationships between the carbonates and
injected sandstone show that fractures and cavities in the
tubular features are commonly filled by injected sandstones, which therefore postdate the tubular features (see
further explanation below).
Carbonate-cemented angular concretions between
2 and 3 cm in size are observed scattered throughout the
mudstones of the Balder Formation, from 5,625 to
5,830 ft (core depth). This type of concretions is
morphologically, genetically and petrographically quite
different (see below) from the tubular features.
Furthermore, they rarely appear concentrated in distinct
layers but they are mostly distributed as single elements
in thick units.
Fig. 4 A Core photograph showing part of the studied core
sequence, which includes thin, brown oil-saturated injected
sandstones (I) and grey mudstones with numerous tubular
carbonate concretions. The injected sandstones are mostly dykes,
which are characterised by sharp, discordant margins (closed
arrows). A thin sandstone sill also occurs (S). Tubular features
form discrete levels (B) or occur as distinct, isolated features (open
arrow). Numbers are core depths in feet. B Twenty-feet-thick
injected sandstone unit (IS) with deformation bands (see text for
details) in mudstone host rock (M). Note the high-angle top and
bottom boundaries of the injected sandstone
328
Fig. 4 B (Contd.)
329
Table 1 Summary of carbon (13C) and oxygen (18O) stable isotope results for carbonate samples and thin-section short description
Depth
(ft)
Sample
d18O
(V-PDB)
d13C
(V-PDB)
Short description/comments
5,355.2
5,355.2
5,355.2
5,355.2
5,355
5,355.5
5,357
5,400
5,400.5
5,400.5
5,400.5
5,400.5
5,400.5
5,401
5,401
5,401
5,401
5,401
5,401
5,404.8
5,404.8
5,404
5,405
5,429.9
5,430.2
5,439
5,459
5,463.2
5,463.2
5,463.2
5,463.2
5,463
5,463
5,463
5,463
5,463
5,463
5,464.8
5,464.8
5,464
5,465
5,466
5,466
5,468
5,468
5,468
5,468
5,468
5,468
5,468
5,468
5,468
5,468
5,469
5,471
5,471
5,471
5,471
5,471
5,471
5,471
5,471
5,518
5,579
5,579.1
5,604
5,609
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Injected sandstone
Injected sandstone
Injected sandstone
Tub. feat. and hem. mud
Irregular tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Hemipelagic mudstone
Angular concretion
Tubular feature
Tubular feature
Injected sandstones
Injected sandstones
Hemipelagic mudstone
Hemipelagic mudstone
Injected sandstone
Inj. sands. and hem. mud
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Injected sandstone
Injected sandstone
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Tubular feature
Hemipelagic mudstone
Injected sandstone
Injected sandstone
Injected sandstone
Stratified sand
Stratified sand
)1.98
)2.40
)4.65
)5.08
)2.03
)2.45
)26.01
)26.50
)13.31
)13.33
)22.16
)22.74
)2.77
)2.97
)0.76
)1.25
)18.43
)17.98
)26.81
)26.54
)4.00
)1.46
)2.18
)7.00
)4.36
)0.83
)1.52
)1.16
)1.78
)14.06
)22.19
)23.25
)0.20
)16.96
)27.44
)27.69
)24.99
)25.21
)0.65
)0.32
)0.90
)1.34
)1.53
)2.11
)1.24
)0.99
)0.65
)1.04
)3.64
)3.97
)1.34
)1.42
)35.14
)34.62
)35.29
)35.34
)29.13
)29.08
)30.26
)30.60
)30.54
)30.75
)16.76
)16.39
)26.80
)26.67
)2.79
)27.27
)0.94
)1.32
)2.25
)2.30
)2.36
)0.14
)0.44
)2.95
)1.99
)32.35
)33.09
)26.05
)25.01
)26.41
)31.14
)31.34
)29.53
)34.74
)1.14
)2.03
)0.91
)1.65
)0.68
)1.34
)4.68
)30.14
)30.46
)30.85
)30.97
)32.62
)32.53
)4.96
)3.34
)2.39
Subrounded feature external part
Subrounded feature external part
Subrounded feature with terrigenous admixture
Subrounded feature with terrigenous admixture
Injected sand oil-stained
Injected sand oil-stained
Poorly cemented, oil-bearing
Sparitic calcite and micrite cements
Sparitic calcite and aragonite cements
Tubular feature porous texture, external part
Tubular feature porous texture, external part
Tubular feature porous texture, central part
Tubular feature porous texture, central part
Zoned with micrite and sparite calcite cements
Calcite from external part of the feature
Sparitic calcite in the internal part of the tube
Sparitic calcite in the internal part of the tube
Mudstone host sed. close to external part of feature
White concretions
Seepage feature elongated, oil-stained
Seepage feature elongated, oil-stained
Thin elongated injected sand
Thin elongated injected sand
Micrite cemented, pyrite framboids along faint lamination
Micrite cemented, pyrite framboids along faint lamination
Poorly cemented, oil-bearing
Quartz+micrite-cemented, oil-bearing
Tubular feature, aragonite cement in porous texture
Tubular feature, aragonite cement in porous texture
Tubular feature, porous texture
Tubular feature, porous texture
Tubular feature, external part of borrow
Tubular feature, external part of borrow
Tubular feature, internal part of borrow
Tubular feature, internal part of borrow
Tubular feature, porous texture
Tubular feature, porous texture
External part of tubular feature oil-stained
Calcite from external part of the feature
Sandy silty admixture close to tubular feature
Sandy silty admixture close to tubular feature
Zoned with micrite and sparitic calcite cements
Tubular feature, central part
Zoned with micrite and sparitic calcite cements
Tubular feature, central part
Tubular feature, central part
Tubular feature, intermediate part
Tubular feature, intermediate part
Tubular feature, intermediate part
Tubular feature, sparitic calcite
Tubular feature, sparitic calcite
Sparitic calcite in the feature
Sparitic calcite in the feature
Zoned with micrite and sparitic calcite cements
Zoned with micrite and sparitic calcite cements
Tubular feature, external part
Tubular feature, external part
Tubular feature, internal part
Tubular feature, internal part
Tubular feature, intermediate part
Tubular feature, intermediate part
Mudstone host rock close to tubular features
Well cemented, oil-bearing
Uncemented, oil-bearing, contains small bands
Well-cemented band, oil-bearing
Well cemented, oil-bearing
Stratified sandstone, well cemented
330
Table 1 (Continued)
Depth
(ft)
Sample
5,610
5,622
5,625
5,625
5,655
5,655
5,655.5
5,658
5,658
5,730
5,730
5,737.2
5,738
5,753
Stratified sand
Stratified sand
Angular concretion
Angular concretion
Angular concretion
Angular concretion
Angular concretion
Angular concretion
Angular concretion
Angular concretion
Angular concretion
Injected sandstone
Injected sandstone
Injected sandstone
d18O
(V-PDB)
d13C
(V-PDB)
)2.46
)2.64
)1.83
)2.06
)5.48
)7.91
)3.87
)4.95
)3.27
)4.07
)0.61
)8.00
)9.04
)7.95
detected under ultraviolet light (illumination source
435 nm) using a Nikon Eclipse E600 microscope with a
UV-2A filter block.
Scanning electron microscope (SEM) analyses were
performed using an ISI ABT-55 SEM with an attached
cathodoluminescence detector (SEM-CL), operated between 10- and 20-kV accelerating voltage, at magnifications ranging from ·15 to ·10,000, and using
secondary electron (SEI) and backscattered electron
(BEI) modes.
Carbon and oxygen isotopic analysis was undertaken
at the SUERC facility in East Kilbride (Scotland), using
a Carbonate Prep System linked with an AP2003 mass
spectrometer. The reproducibility of the system is
±0.1& for both d13C and d18O values. All data are
reported as per mil deviation from the V-PDB international standard, and appropriate internal correction
factors were applied.
Results
Petrographic observations
Petrographic observations for the sample analysed are
summarised in Table 1. Stratified sandstones consist of
70% grains, 20–25% cement, and have 5–10% porosity
(Fig. 5A). The grains are fine to medium grained and
consist of 90% quartz and 10% K-feldspar and mica.
Cement consists of 80% micritic carbonate, 10% pyrite
framboids and 10% quartz.
Two types of injected sandstones are observed
throughout. One type was poorly cemented and heavily
oil-saturated. A second type appeared mostly moderately cemented and oil-saturated. The injected units have
similar petrographic characteristics as the stratified
sandstones and consist of 65% grains, 10% cement and
have 25% porosity. The grains were mostly angular and
fractured. The cement consists of 40% quartz overgrowths, 40% micritic carbonate and 20% pyrite. Pyrite
Short description/comments
Well cemented, oil-bearing
Well cemented, oil-bearing
Well cemented with sparitic calcite cement
Well cemented with sparitic calcite cement
Well cemented with sparitic calcite cement
Angular concretion, external part
Well cemented with sparitic calcite cement
Well cemented with sparitic calcite cement
Angular white concretion
Angular concretion, sparitic cement
Angular concretion, sparitic cement
Poorly cemented, oil-bearing, contains bands
Cemented, oil-bearing, contains bands
Poorly cemented, oil-bearing, contains bands
framboids predate micritic carbonate, which in turn
predates quartz overgrowths.
In several sandstone dykes and sills, bands with
differing textural characteristics were observed. These
bands are characterised by a drastic decrease in porosity
(down to 5%), by a reduction in grain size due to the
large amount of fractured grains, and by the diffuse
presence of pyrite framboids in trails parallel to the
orientation of the bands (Fig. 5B). BEI and SEM-CL
observations in these bands revealed that the extensively
fractured detrital quartz and feldspar grains are cemented with differently luminescing cements (Fig. 5C,
D). Petrographic and textural characteristics indicate
that these bands are deformation bands (Mair et al.
2000). CL microscopy of the micritic cement in the injected sandstones revealed no luminescence.
The observed tubular features exhibit different sizes
and shapes. The majority have a tubular shape with a
diameter ranging from a few millimetres up to 2–3 cm
(Fig. 6A–C). Thin sections cut perpendicular to the long
axis of the tubular features revealed concentric zones of
different carbonate cements which grew towards the
central part of the structure (Fig. 6D). The external part
was commonly characterised by clay-rich micritic cement with pervasive pyrite framboids, locally forming
aggregates. The internal part commonly consisted of
sparitic calcite or occasionally aragonite. The central
part of the tubular features was commonly void, but
occasionally the cavity was filled with oil or sandstone
(Fig. 6C). In some instances, the whole feature appeared
completely oil-stained. CL microscopy revealed that the
early micritic calcite cement was dull-luminescent,
whereas the later blocky and fibrous calcite filling the
internal part of the features was composed of alternating
zones of bright- and dull-luminescing calcite (Fig. 6E).
No evidence of dissolution was seen in any of the samples, indicating a continuous precipitation history of the
carbonate. Sections taken parallel to the long axis of the
tubular features demonstrate that their diameter can
gradually vary in size and that the direction of the long
axis can change at angles of up to almost 90.
331
Fig. 5 A Plane light microscope image of stratified sandstone;
quartz grains are cemented by mostly micritic calcite with pervasive
framboidal pyrite, B Plane light photo-mosaic of injected sandstone
showing deformation band in the central part (solid lines). C SEM
image on BEI mode showing compact texture of quartz grains
along a deformation band in an injected sandstone. D Same image
seen with SEM-CL detector shows fractured detrital quartz
cemented with differently luminescing quartz cement
In rare cases the tubular features displayed more
irregular shapes and porous textures. These irregularshaped features were entirely composed of coarsegrained sparry calcite with aragonite aciculae in the
internal parts. CL microscopy revealed that the calcite
and aragonite were composed of alternating luminescing
and non-luminescing zones.
Angular carbonate concretions observed distributed
throughout the mudstones of the Balder Formation
were composed of sparitic calcite and dolomite cement.
These crystals were angular and fractured and
commonly showed calcite overgrowths which cemented
all the crystals together. A similar type of concretion,
observed in the nearby Harding Oil Field, was
interpreted as carbonate-cemented coprolites which
underwent different stages of diagenesis during burial
(Watson 1993).
Fluid inclusions
All sandstone samples analysed revealed the presence of
monophase primary aqueous inclusions (type A) and
monophase yellow-fluorescing primary oil inclusions
(type B) within carbonate and quartz cements (Table 2).
332
Fig. 6 A Detail of core showing some of the tubular features
(outlined by dashed lines). B Detail of one of the tubular features
showing concentric zones of different carbonate cements, and oil
stain in internal part. C Tubular features sampled close to injected
sandstones show sparitic calcite, occasionally oil-stained, and
lithified injected sandstone filling the central void part of the
feature. D Section of tube perpendicular to the long axis (plane
light) showing micritic cement (M) and sparitic calcite (S). E CL
image showing dull luminescence for micritic cement and alternating zones of bright and dull luminescence for sparitic calcite
In the stratified sandstones, aqueous and fluorescing
inclusions were observed within the intra-granular cement and in the quartz fractures and overgrowths. In the
injected sandstones the inclusions were observed in the
grain fractures, tracing the rims of the quartz overgrowths (Fig. 7A, B), trapped within the micritic cement
(Fig. 7C, D) and along the fragmented surfaces of the
grains in the deformation bands (Fig. 7E, F). The
observed deformation bands reveal higher amounts of
fluorescing inclusions, which are mostly concentrated
around the fragmented grains and the fractures within
the grains.
The tubular features contain abundant one-phase
aqueous inclusions as well as both one- and two-phase
oil inclusions in the carbonate cement. Oil inclusions are
far less common in comparison to the injected sandstone
samples. The micritic cements contained one-phase
aqueous inclusions and small oil inclusions in intracrystal sites, whereas the aragonite and sparite crystals
contained larger one-phase aqueous inclusions and
fluorescing one- and two-phase oil inclusions which
occurred either within trails following crystal growth
333
Table 2 Summary of most representative samples containing primary fluid inclusion populations. L Liquid, V vapour, A aqueous, B oil, P
primary
Depth
(ft)
Sample
Host
Contents at
room temp.
Occurrence
Size range
(lm)
Morphology
Degree
of fill
5,357
Injected sand
Quartz
LB
5,400.5
Irregular tubular
feature
Sparitic calcite
5,468
Tubular feature
Sparitic calcite
5,469
Tubular feature
Micritic calcite
5,579
5,610
Injected sandstone
Stratified sandstone
Micritic calcite
Quartz
5,622
Stratified sandstone
Micritic calcite
5,737.2
Injected sandstone
Quartz
LA
LBVB
LBVB
LA
LB
LBVB
LA
LB
LB
LA
LB
LB
LA
LB
LA
LB
LB
LB
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
P;
<3
<3
<5
<15
<20
<4
<7
<20
<4
<7
<3
<3
<3
<3
<4
<3
<3
<3
<3
<3
Subrounded
Subrounded
Subrounded
Irregular
elongated
Subrounded
Subrounded
Irregular
Subrounded
Elongated
Elongated
Subrounded
Subrounded
Subrounded
Subrounded
Subrounded
Subrounded
Subrounded
Subrounded
Subrounded
100
100
1.00
0.75
0.85
100
100
0.85
100
100
100
100
100
100
100
100
100
100
100
100
zones or within isolated populations inside the crystals
(Fig. 7G, H). The size, shape, and degree of fill observed
in the two-phase inclusions suggest that they are likely to
be the result of stretching within the weak carbonate
crystals (Goldstein 1986).
Isotopes
Figure 8 shows the results of the oxygen and carbon
stable isotope analyses of carbonate cements associated
with tubular features, injected sandstones, stratified
sandstones, concretions and host mudstone sediments
(Table 1). All the carbon isotope compositions have
negative values.
The few injected sandstones containing enough carbonate cement to measure gave a narrow range of values
()26.8&<d13C<)22.2& and )2.4&<d18O<)1.2&).
The majority of the samples analysed from the
tubular features revealed d13C values clustered between
)35.3 and )18&, and d18O values varying from )2.9 to
)0.1&. Only a small cluster of the samples, drilled from
transitional zones on the most external part of the
tubular features, yielded less depleted 13C values
()16.8&<d13C<)13.3&) and more depleted 18O values ()5&<d18O<)3.6&). The concretions, distributed
throughout the studied core interval, exhibit a moderate
13
C depletion ()16.9&<d13C<)0.6&) and a wide
range of d18O values ()5.5&<d18O<)1.8&) which
generally decrease with depth. The small portion of
micritic cement contained in the mudstone host rock
showed slight 13C depletion, whereas the 18O values
showed the highest depletion of all the samples in this
study.
overgrowth
fractures
intra-crystal site
intra-crystal site
inter-crystal site
intra-crystal site
intra/inter-crystal site
intra-crystal site
intra-crystal site
inter-crystal site
inter crystal site
overgrowth
overgrowth
fractures
inter-crystal site
inter-crystal site
overgrowth
overgrowth
fractures
bands
Discussion
The origin of diagenetic carbonates
Broadly similar isotopic compositions for authigenic
carbonate in tubular features and the surrounding
injected sandstones suggest a common source of precipitation. Cement precipitation temperatures below
50 C are indicated by the presence, in all of the samples,
of abundant primary monophase aqueous and oil
inclusions within the carbonate cements (Goldstein
2001). This in itself does not constrain when cementation
occurred, since 50 C is about the maximum (presentday) burial temperature experienced by the Gryphon
Field. If the described diagenetic carbonate precipitated
from a marine pore fluid, with d18O around )1 to
)2SMOW, (Shackleton and Kennett 1975), the calculated
range of precipitation temperatures for the two extreme
d18O values of the main cluster ()3 and 0&) has a range
between 14 and 27 C (Friedman and ONeil 1977,
Fig. 9). However, regional studies (Watson et al. 1995;
Stewart et al. 2000) indicate that during the Palaeogene
18
O-depleted meteoric fluids (composition around
)10&SMOW, Fallick et al. 1985) flushed the reservoirs in
the southern part of the Beryl Embayment of the South
Viking Graben. A single meteoric origin for the pore
fluid can be excluded, given that it would result in precipitation temperatures well below 0 C (Fig. 9). The
temperature of 27 C deduced for a pure marine pore
fluid also represents an extreme estimate, resulting in a
maximum burial depth of carbonate cementation close
to 1 km (assuming a geothermal gradient of 33 C/km;
Barnard and Bastow 1991). However, it is very likely
that some mixing between meteoric and marine pore
334
335
Fig. 8 Cross-plot of carbon
(13C) and oxygen (18O) stable
isotope compositions for
carbonate cements
fluids took place (Watson et al. 1995; Stewart et al.
2000). Given that sand injection is thought to take place
at no more than a few hundreds metres of burial
(Lonergan et al. 2000; Jolly and Lonergan 2002; Huuse
et al. 2003), carbonate cementation took place prior to
increased burial of the section.
The diagenetic evolution of tubular features
and injected sandstones
Tubular features with shapes similar to those described
here, and of scale varying from centimetre to decimetre,
have been recognised in a range of different geological
settings where they have been interpreted as modern and
palaeo-carbonate seep structures (Kulm and Suess 1990;
von Rad et al. 1996; Aiello et al. 1999; Conti and Fontana
1999; Stakes et al. 1999; Kenyon et al. 2002; K. Campbell,
personal communication). In all these cases, the authigenic carbonate was inferred to have precipitated in
conduits along which hydrocarbon-rich fluids, mostly
methane, were seeping close to the subsurface. In the
present study also, this hypothesis is confirmed by geob
Fig. 7 A Plane light microscope image of quartz grains in injected
sandstone with small amount of micritic cement and numerous
quartz overgrowths. B UV microscopy shows fluorescing oil
inclusions tracing the rims of the quartz overgrowths (open arrows
indicate fluorescing inclusions). C Plane light image of quartz
grains surrounded by framboidal pyrite aggregates, organic matter
and micritic cement. D UV microscopy shows fluorescing oil
inclusions (open arrows) around the quartz grains and in the inter-,
intra-crystal sites within the micritic cement. E Plane light image of
quartz grains compressed and fractured in a deformation band.
F UV microscopy shows fluorescing oil inclusions (open arrows)
along the fractures. G Plane light image of sparitic calcite cement in
the internal part of a tubular feature; brown two-phase oil
inclusions (closed arrows) are visible inside the calcite crystals and
at the inter-crystal sites. H UV microscopy shows fluorescing oil
inclusions (open arrows) in the calcite cement
chemical and petrographic analyses. The significant 13C
depletion of cement phases observed within the tubular
features strongly indicates a contribution of carbon from
hydrocarbons. This suggests microbially mediated oxidation coupled with sulphate reduction during burial
(Ritger et al. 1987; Suess and Whiticar 1989; Boetius et al.
2000). Isotopic results, petrographic characteristics and
the absence of a chemosymbiotic fauna reflect the precipitation of cement within buried sediments, below the
seawater interface. The local presence of aragonite, the
precipitation of which is favoured at high SO42) concentrations and Mg2+/Ca2+ ratios (Burton 1993), indicates
seafloor or close-subsurface conditions (Aloisi et al. 2002).
This supports the idea that the tubular feature-rich
intervals were close to the seafloor during their formation.
The fact that these features are present only in the upper
Frigg Formation could indicate that these shales were at
that time being deposited along with the precipitation of
the authigenic carbonate (i.e. described tubular features).
The mineralogical changes in the concentric zones clearly
indicate different growth phases of carbonate cement in an
environment which was constantly supporting the precipitation of carbonate cement. This is also confirmed by
CL microscopy which showed zoned carbonate cements,
suggesting gradual precipitation of carbonate cement
which accompanied hydrocarbon-rich fluid escapes (Jonk
et al. 2003b; Mazzini et al. 2003). The presence of fluorescing oil inclusions in the carbonate cement observed in
intra- and inter-crystal sites, combined with the presence
of substantial oil staining infilling voids, indicates that
petroleum seepage was ongoing at shallow burial. As
thin cemented sandstones occasionally infill the internal
cavities of the tubular structures, the non-cemented voids
were likely to be later exploited during a phase of sand
injection. The possibility that hydrocarbons exploited
previously existing, buried Lamellibranchia tubeworm
structures or bioturbation burrows cannot be discarded.
However, no evidence of mucus lining, internal structure
336
Fig. 9 Plot indicating d18OSMOW for pore-fluid composition and
temperature of precipitation with curves of two extreme d18O
values for carbonate cements. Arrows indicate the range of
temperature precipitation for pure meteoric pore fluids, pure
marine pore fluids, and mix of marine/meteoric pore fluids
or branching in the structures was observed. The material
filling these structures would have had to be removed and
replaced by hydrocarbon-derived authigenic carbonate.
Alternatively, if these degassing conduits formed in the
subsurface soft sediments, the change in size and orientation of the conduits suggests that sedimentary structures
or discontinuities within the mudstone host unit controlled the gas distribution in the sediment and the shape
of the conduits. The lower oxygen and higher carbon
values recorded for the samples drilled from the external
parts of the tubes suggest possible mixing with the mudstone host rock (which is typically less 13C-depleted and
more depleted in 18O).
The injected sandstones show isotopic characteristics
similar to the carbonate tubular features, suggesting that
similar petroleum fluids seeped from the reservoir. It
seems realistic to consider that petroleum (oil and gas)
filled the injected sandstones soon after the injection
process, and was still present after the burial of the
section. This is evidenced and supported by the occurrence of primary petroleum inclusions within carbonate
cement which formed at shallow burial (well below
1 km). Moreover, the presence of primary petroleum
inclusions in both earlier (micritic cement and quartz
fracture-fills within deformation bands, Jonk et al.
2003a) and later (quartz overgrowths which formed
close to the present-day burial depth, Worden and
Morad 2000) diagenetic cements suggests that petroleum
may have entered the sandstones during the injection
process and remained until the present-day. The negative carbon isotopic values for carbonate cements within
the injected sandstones and the significant amounts of
oil inclusions suggest that petroleum was actively
sourcing bicarbonate carbon through microbial oxidation of hydrocarbons (Irwin et al. 1977) to the precipitating calcite. This hypothesis is also supported by
measurements performed at petroleum seepage sites in
the northern Gulf of Mexico (Roberts et al. 1990;
Roberts and Aharon 1994), where results indicate that
diagenetic carbonates with comparable d13C depletion
originate from the microbial degradation of hydrocarbons ranging from crude oil to biogenic methane. In the
study described here, the biogenic or thermogenic origin
of methane remains uncertain.
Model
Crosscutting relationships between the tubular features
and the surrounding injected sandstones indicate that
injected sandstones postdated the degassing features.
The formation of the tubular features occurred during a
first phase in the shallow subsurface where gas and oil
from the reservoir migrated along fractures and faults
(Fig. 10A). Seepage of gas in the shallow subsurface
occurred in the uncompacted hemipelagic sediment. The
formation of authigenic carbonate deposits on the seafloor cannot be excluded, but limitations of a core-based
study do not allow the laterally extensive sampling
which would be required to prove this process. During a
second phase, sandstone dykes and sills were generated
by sand remobilisation at shallow depth from the main
reservoir in the Balder Sandstones (Fig. 10B). These
units crosscut the seepage features, which were overlying
the reservoir. Precipitation of authigenic carbonate
within both degassing features and injected sandstones
was facilitated by supply of bicarbonate through oxidation of petroleum (both methane and oil). It is not
possible to establish whether oil was present during the
injection phase (although it is certain that petroleum
moved into injected sandstones very soon after their
formation) but it appears that injected sandstone units
were used as pathways for oil migration from the reservoir up to shallow depth (Fig. 10C). Several injected
sandstones are located along the conduit-rich horizons.
As comparable yellow-fluorescing inclusions were observed in all of the samples, it is likely that petroleum
fluids migrated from the reservoir through the host
mudstones, inducing the precipitation of authigenic
337
carbonate in the tubular features and in the injected
sandstones (Jonk et al. 2003b; Mazzini et al. 2003).
Precipitation of authigenic carbonate in both features
fossilised the petroleum escape pathway and highlights
the active role which petroleum plays in the precipitation
of authigenic carbonate.
Conclusions
1. Combined petrographic and geochemical analyses
indicate that petroleum leakage from the reservoir
occurred in the shallow subsurface in the southern
part of the Gryphon Oil Field. Zoned authigenic
carbonates precipitated along degassing conduits
provide evidence for a rare example of palaeo-seepage above a hydrocarbon reservoir.
2. Tubular degassing features and injected sandstones
both formed during shallow burial. Analyses show
that petroleum seepage occurred during the early
phase of formation of the tubular degassing features,
and continued during the later phase of sand injection. Both those features exhibit oil saturation and/or
a substantial amount of oil inclusions within the cement. The oil inclusions would be consistent with a
model in which hydrocarbons enhanced the injection
process, but we cannot prove this.
3. Injected units and degassing conduit-rich horizons
were likely to be exploited by subsequent phases of
oil leakage, as oil inclusions and oil stains currently
occur in both these features.
Acknowledgements This paper is published with the permission of
Kerr McGee North Sea Ltd. and the Gryphon Field partners.
The views and opinions expressed by the authors may not
always necessarily reflect the standpoint of the Gryphon Field
partners. The authors would like to thank Catherine Pierre, Kevin
Purvis and John Woodside for their critical review of the manuscript and helpful ideas for its improvement. Tony Fallick and
Andrew Tait (SUERC) are thanked for their support during
isotopic analyses.
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B Phase of injections from the reservoir with moderate oil seepage.
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