ORIGINAL

Adriano Mazzini Æ D. Duranti Æ R. Jonk Æ J. ParnellB. 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 per-formed on a North Sea core from the Gryphon Field re-veal the presence of palaeo-degassing features surroundedby injected sandstones in the Eocene interval. The injectedsandstones are oil-stained and poorly cemented by car-bonate and quartz. 18O isotope analyses indicate thatcarbonate cementation occurred during shallow burial(likely less than about 300 m). Depleted 13C (around)30& V-PDB) carbonate cement suggests that bicar-bonate was derived from the microbial oxidation of oiland gas. Late quartz overgrowths enclose oil present in theinjected units. The tubular degassing conduits are com-posed of zoned cements and have d18O and d13C isotopevalues similar to the injected sandstones, indicating thatoil and gas seepage induced the precipitation of authigeniccarbonate in the shallow subsurface. Oil inclusions ininter- and intra-crystal cement sites in both injectedsandstones and degassing conduits indicate that oil seep-age was an ongoing feature at shallow burial. A proposedmodel involves oil and gas seepage and the formation ofthe degassing conduits, followed by a sand injectionphase. It seems likely that oil and gas continued toleak towards the seabed by exploiting the network ofpermeable injected sandstones and the horizons of porousdegassing features.

Introduction

Focussed fluid migration in the shallow crust is a wide-spread phenomenon which is increasingly gaining atten-tion but is still not fully understood. Gas escape fromburied units is one of themost obvious expressions of fluidmigration. Fluids can follow different pathways, gener-ating diverse geological structures and phenomena. Theoccurrence of fluid and gas seepage is manifested on theseafloor by the presence of pockmarks, diapirs, deep-water coral reefs and mud volcanoes (Hovland and Judd1988).A diversity of depositional and tectonic settings hasbeen recognised as preferential locations for seeping andventing activity. Gas seepage, especially methane (coldseeps), is observed in offshore areas of active continentalmargins (Le Pichon et al. 1990; Sakai et al. 1992; Corselliand Basso 1996; Bohrmann et al. 1998), and regions ofrapid sedimentation at passive continental margins(Hovland et al. 1987; Hovland 1992; Paull et al. 1992;Roberts and Aharon 1994; Vogt et al. 1997). This phe-nomenon is frequently associated with the growth ofdistinct chemosynthetic communities (Sibuet and Olu1998) and, more commonly, with the occurrence of au-thigenic carbonate mineralisation as a consequence of themicrobially mediated oxidation of methane (Ritger et al.1987; Boetius et al. 2000). Carbonate deposits can vary insize from mm-scale carbonate micro-slabs (and minera-lised veins) to extensive deposits of several hundredsmeters in scale (Kelly et al. 1995; Aloisi et al. 2000).

Several of these features can occur on the seafloorabove petroleum reservoirs. Examples of gas, andoccasionally oil, leaking from reservoirs include seepsfrom the Gulf of Mexico (Sassen et al. 1993), the south-eastern Mediterranean (Coleman and Ballard 2001), theNorth Sea (e.g. UK Block 15/25, Judd et al. 1994) andthe southern and eastern Skagerrak (Hovland 1991).Even at depth, fluid escape from hydrocarbon fields isone of the most frequent phenomena revealed by sub-surface investigation tools in hydrocarbon explorationand production. Large-scale gas leakage is commonly

A. Mazzini (&) Æ D. Duranti Æ R. Jonk Æ J. ParnellB. T. Cronin Æ A. HurstDepartment of Geology and Petroleum Geology,University of Aberdeen, Meston Building,King�s College, Aberdeen, AB24 3UE UKE-mail: a.mazzini@abdn.ac.ukTel.: +44-1224-273435Fax: +44-1224-272785

M. QuineKerr McGee North Sea Limited,Ninian House, Crawpeel Rd.,Aberdeen, AB12 3LG, UK

Geo-Mar Lett (2003) 23: 323–339DOI 10.1007/s00367-003-0145-y

observed on seismic data as acoustic anomalies showingvertical transparent areas and masked reflectors abovereservoirs (Hovland and Judd 1988; Heggland 1998).Injected sandstones are frequently observed above thePalaeogene reservoirs of the northern North Sea (Jens-sen et al. 1993; Dixon et al. 1995; Lonergan et al. 2000).They are increasingly recognised in new petroleumprovinces, such as the Angolan offshore and theNorwegian Sea (Møller et al. 2001).

All the documented evidence of gas escape fromhydrocarbon reservoirs are present-day features. An-cient gas escape products above hydrocarbon reservoirsare virtually undocumented. This paper focuses on car-bonate seep features and injected sandstones formingduring hydrocarbon leakage above the Palaeogene res-ervoir of the Gryphon Oil Field (northern North Sea).

Geological background

The Gryphon Oil Field is located in Block 9/18b in thesouthern part of the Beryl Embayment of the SouthViking Graben (northern North Sea; Fig. 1A). After themajor Mid–Late Jurassic rifting event, the North Seabasin went through a phase of relative tectonic quiescencein the Late Cretaceous and became starved of sediments.During the Early Tertiary the thermal uplift of the EastShetland Platform renewed clastic supply and turned theSouth Viking Graben into a major depocentre (Newmanet al. 1993; Dixon et al. 1995). Large-scale deltas andshelfal systems, with associated deep-water facies, formedsouth-eastwards of the uplifted areas. In the Early Pal-aeocene, deep-water sedimentation consisted of extensive,sheet-like units of sand with subordinate mud, which arebelieved to represent large-scale submarine fans (DenHartog Jager et al. 1993; Bowman 1998). Smaller-scalesand-prone bodies enclosed by mud gradually becamemore common in the Late Paleocene and Eocene (And-erton 1997). These bodies are mainly interpreted as deep-water channel fills (Newton and Flanagan 1993) or asaccumulations of large-scale failures of deltaic and near-shore sediments. The Balder Sandstones (Fig. 2, UpperPalaeocene and Lower Eocene) in the South VikingGraben represent this transition to more isolated sandbodies. In the Bruce-Beryl Embayment the deep-watersandstone bodies of the Balder Formation were depositedat or near the toe of a complex delta system, representedby the Dornoch Formation (Upper Palaeocene, Timbrell1993). They are interpreted as the deposits of large-scaleretrogressive slides and slumping on the delta front, whichwere caused by the high sedimentation rates and steepprofiles (Newman et al. 1993; Dixon et al. 1995). The well-sorted, fine grain size and homogeneous nature of thesedeep-water deposits suggest resedimentation from awave-dominated shelf delta. The forced anticline whichformed above the Crawford Ridge, a relict Mesozoicstructural relief, acted as a barrier and ponded the massflows coming from the delta (Fig. 1A, Newman et al.1993; Purvis et al. 2002). Delta front failure and resedi-

mentation occurred during a second-order rise in sea level(Dixon et al. 1995). Regional tectonic events, related tothe East Shetland Platform uplift, controlled the sea leveland formed the Early Palaeogene unconformities of theNorth Sea (Jones and Milton 1994; White and Lovell1997).

In the same period, extensive units of volcaniclasticmaterial were deposited in this deep-water settingand formed the Late Palaeocene Balder Tuffs. Boththe volcanic activity and the Early Tertiary uplift of theEast Shetland Platform occurred in response to the

Fig. 1 A Geological setting of the Gryphon Field area. Darkshading Main structural features, dotted areas main oil fields, lightshading highs, non-shaded areas basinal areas. B Outline of theGryphon Field and location of the main wells and the studied coredwell (9/18b-13). Location map in inset. Redrawn and modified afterNewman et al. (1993)

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opening of the North Atlantic Ocean (Haaland et al.2000).

These base-of-slope deep-water sandstone bodies formthe main reservoir of the Gryphon Oil Field, which ex-tends over an area of approximately 14 km2 (3,500 acres)inUKBlock 9/18b (Fig. 1). The field contains lowAPI oil(21.51�) and has a large gas cap. In theGryphonField, thesandstone bodies are up to 120 m thick, with steep sides(up to 18�). The sandstones are clean, fine to mediumgrained, poorly cemented, generally highly porous (30–33%) andmainly structureless.Over 2,000 feet of core hasbeen recovered from 11 wells in the field. Injected sand-stone units at core and seismic scale occur both in theBalder Formation and in the overlying Frigg Formation(Purvis et al. 2002). The examined section was cored inwell 9/18b-13, which is located at the southern border ofthe main Gryphon Field (Fig. 1B).

Core description

The examined vertical cored section is nearly 500 feetlong. Cores are approximately 6 inches in diameter and

well preserved. An almost complete record of the FriggFormation and a large part of the Balder Formation arepreserved in this core (Fig. 3A). The lowermost part ofthe Balder Formation, approximately 100 feet, was notcored. The occurrence of thick sandstone units in thelowermost uncored part of this formation can be in-ferred from wireline log interpretation and inspection ofdrilling cuttings (Fig. 3B). Three main lithotypes arepreserved in the cored record: tuffs, sandstones andmudstones.

Tuffs

This lithotype is formed by thin, white to light greenbeds of fine-grained volcaniclastic material (Hatton et al.1992; Newman et al. 1993). The beds have a sharp baseand gradational top. They may display normal gradingand, rarely, parallel or low-angle lamination. These bedsof volcaniclastic material characterise several distinctintervals of the Balder Formation. In total they formapproximately 5% of the studied cored record.

These tuffs were mainly deposited by sediment grav-ity flows, as can be inferred by the internal structuresand bedding surfaces characteristics. The volcanicmaterial was redeposited in the deep-water environmentfrom temporary offshore storage areas. Similar units ofvolcaniclastic material are very common in most of thecored Palaeocene sequences of the northern North Sea.

Sandstones

Sandstone units form approximately 30% of the coredinterval. Sandstones are arkosic and medium to finegrained. Two main sandstone lithofacies are recognisedin this core: stratified sandstones and injected sand-stones.

Stratified sandstones

This lithofacies is composed of sandstones which pre-serve the original depositional structures. Only one thickbedset of amalgamated, fine-grained stratified sand-stones is present in this core (core depth 5,597–5,625 ft;Fig. 3). Individual beds are up to 6 ft thick with parallellamination and erosional bases. The primary stratifica-tion is deformed and obliterated by numerous pore-fluidescape structures (cm-scale pillars) in the uppermost partof this bedset (core depth 5,597–5,604 ft). The uppercontact between this sandstone package and the over-lying mudstone is sharp and discordant with respect tothe mudstone bedding.

This bedset of stratified sandstones is interpreted ashaving been deposited by sediment gravity flows, inparticular turbidity currents. The upper part of thebedset was affected by intense fluidisation, as shown bythe numerous pore-fluid escape structures. Fluidisationwas associated with sand remobilisation which produced

Fig. 2 Generalised stratigraphic column of the South VikingGraben with inset showing the lithostratigraphy of the GryphonField (redrawn and modified after Joy 1997)

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the discordant bedset top and may have produced theinjected 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), withmargins discordant to the bedding of the adjacentmudstones (Fig. 4A). Margins are very sharp, indentedand frequently associated with deformation in theencasing mudstones. Sills are more difficult to recognisebecause of their bedding-concordant relations, but theirmargins have the same characteristics. These injectedunits reach, in one case, up to 20 ft in vertical thickness(core depth 5,735–5,758 ft, Fig. 4B). The total of thesandstone units in the cored part of the Frigg Formationconsists of this lithofacies. These injected units areinterpreted as having been produced by fluidisation,sand remobilisation and injection during burial. Injectedsand units are common in the Palaeogene deep-watersequence of the northern North Sea (Dixon et al. 1995;Lonergan et al. 2000; Duranti et al. 2002).

Mudstones

Homogeneous or weakly laminated mudstones form themost abundant lithotype (approximately 65%) in thecored record from this well. Mudstones are dark greyand weakly bioturbated in the Balder Formation; theyare lighter, grey-green and locally strongly bioturbatedin the Frigg Formation.

Various kinds of diagenetic carbonate features occurthroughout the cored mudstones and are locally veryabundant. 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 beconcentrated in discrete, m-thick levels at, for example,5,462–5,474 and 5,482–5,486 ft (core depth) and they areoften associated with injected sandstones (Fig. 3).Crosscutting relationships between the carbonates andinjected sandstone show that fractures and cavities in thetubular features are commonly filled by injected sand-stones, which therefore postdate the tubular features (seefurther explanation below).

Carbonate-cemented angular concretions between2 and 3 cm in size are observed scattered throughout themudstones of the Balder Formation, from 5,625 to5,830 ft (core depth). This type of concretions ismorphologically, genetically and petrographically quitedifferent (see below) from the tubular features.Furthermore, they rarely appear concentrated in distinctlayers but they are mostly distributed as single elementsin thick units.

The cored mudstones were mainly deposited ashemipelagites with some possible contributions fromvery fine-grained, low-density turbidity currents. Theorigin of the carbonate features is discussed below.

Materials and methods

A collection of polished thin sections was preparedfrom stratified sandstones, injected sandstones, tubularfeatures, nodules and concretions sampled from theGryphon core 9/18b-13 (Table 1). Polished slabs andthin sections were studied using standard petrographicand cathodoluminescence techniques. Cathodolumines-cence (CL) was conducted using the Citl Cold CathodeLuminescence 8200 mk3, attached to a Nikon Optiphot-POL microscope. Fluorescing petroleum inclusions were

Fig. 4 A Core photograph showing part of the studied coresequence, which includes thin, brown oil-saturated injectedsandstones (I) and grey mudstones with numerous tubularcarbonate concretions. The injected sandstones are mostly dykes,which are characterised by sharp, discordant margins (closedarrows). A thin sandstone sill also occurs (S). Tubular featuresform discrete levels (B) or occur as distinct, isolated features (openarrow). Numbers are core depths in feet. B Twenty-feet-thickinjected sandstone unit (IS) with deformation bands (see text fordetails) in mudstone host rock (M). Note the high-angle top andbottom boundaries of the injected sandstone

Fig. 3. A Stratigraphic subdivision of cored and studied intervalfrom well 9/18b-13. B Stratigraphic log of well 9/18b-13, includingwater, oil and gas columns

b

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Fig. 4 B (Contd.)

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Table 1 Summary of carbon (13C) and oxygen (18O) stable isotope results for carbonate samples and thin-section short description

Depth Sample d18O d13C Short description/comments(ft) (V-PDB) (V-PDB)

5,355.2 Tubular feature )1.98 )26.01 Subrounded feature external part5,355.2 Tubular feature )2.40 )26.50 Subrounded feature external part5,355.2 Tubular feature )4.65 )13.31 Subrounded feature with terrigenous admixture5,355.2 Tubular feature )5.08 )13.33 Subrounded feature with terrigenous admixture5,355 Injected sandstone )2.03 )22.16 Injected sand oil-stained5,355.5 Injected sandstone )2.45 )22.74 Injected sand oil-stained5,357 Injected sandstone Poorly cemented, oil-bearing5,400 Tub. feat. and hem. mud Sparitic calcite and micrite cements5,400.5 Irregular tubular feature Sparitic calcite and aragonite cements5,400.5 Tubular feature )2.77 )18.43 Tubular feature porous texture, external part5,400.5 Tubular feature )2.97 )17.98 Tubular feature porous texture, external part5,400.5 Tubular feature )0.76 )26.81 Tubular feature porous texture, central part5,400.5 Tubular feature )1.25 )26.54 Tubular feature porous texture, central part5,401 Tubular feature Zoned with micrite and sparite calcite cements5,401 Tubular feature )4.00 )14.06 Calcite from external part of the feature5,401 Tubular feature )1.46 )22.19 Sparitic calcite in the internal part of the tube5,401 Tubular feature )2.18 )23.25 Sparitic calcite in the internal part of the tube5,401 Hemipelagic mudstone )7.00 )0.20 Mudstone host sed. close to external part of feature5,401 Angular concretion )4.36 )16.96 White concretions5,404.8 Tubular feature )0.83 )27.44 Seepage feature elongated, oil-stained5,404.8 Tubular feature )1.52 )27.69 Seepage feature elongated, oil-stained5,404 Injected sandstones )1.16 )24.99 Thin elongated injected sand5,405 Injected sandstones )1.78 )25.21 Thin elongated injected sand5,429.9 Hemipelagic mudstone Micrite cemented, pyrite framboids along faint lamination5,430.2 Hemipelagic mudstone Micrite cemented, pyrite framboids along faint lamination5,439 Injected sandstone Poorly cemented, oil-bearing5,459 Inj. sands. and hem. mud Quartz+micrite-cemented, oil-bearing5,463.2 Tubular feature )0.65 )35.14 Tubular feature, aragonite cement in porous texture5,463.2 Tubular feature )0.32 )34.62 Tubular feature, aragonite cement in porous texture5,463.2 Tubular feature )0.90 )35.29 Tubular feature, porous texture5,463.2 Tubular feature )1.34 )35.34 Tubular feature, porous texture5,463 Tubular feature )1.53 )29.13 Tubular feature, external part of borrow5,463 Tubular feature )2.11 )29.08 Tubular feature, external part of borrow5,463 Tubular feature )1.24 )30.26 Tubular feature, internal part of borrow5,463 Tubular feature )0.99 )30.60 Tubular feature, internal part of borrow5,463 Tubular feature )0.65 )30.54 Tubular feature, porous texture5,463 Tubular feature )1.04 )30.75 Tubular feature, porous texture5,464.8 Tubular feature )3.64 )16.76 External part of tubular feature oil-stained5,464.8 Tubular feature )3.97 )16.39 Calcite from external part of the feature5,464 Injected sandstone )1.34 )26.80 Sandy silty admixture close to tubular feature5,465 Injected sandstone )1.42 )26.67 Sandy silty admixture close to tubular feature5,466 Tubular feature Zoned with micrite and sparitic calcite cements5,466 Tubular feature )2.79 )27.27 Tubular feature, central part5,468 Tubular feature Zoned with micrite and sparitic calcite cements5,468 Tubular feature )0.94 )32.35 Tubular feature, central part5,468 Tubular feature )1.32 )33.09 Tubular feature, central part5,468 Tubular feature )2.25 )26.05 Tubular feature, intermediate part5,468 Tubular feature )2.30 )25.01 Tubular feature, intermediate part5,468 Tubular feature )2.36 )26.41 Tubular feature, intermediate part5,468 Tubular feature )0.14 )31.14 Tubular feature, sparitic calcite5,468 Tubular feature )0.44 )31.34 Tubular feature, sparitic calcite5,468 Tubular feature )2.95 )29.53 Sparitic calcite in the feature5,468 Tubular feature )1.99 )34.74 Sparitic calcite in the feature5,469 Tubular feature Zoned with micrite and sparitic calcite cements5,471 Tubular feature Zoned with micrite and sparitic calcite cements5,471 Tubular feature )1.14 )30.14 Tubular feature, external part5,471 Tubular feature )2.03 )30.46 Tubular feature, external part5,471 Tubular feature )0.91 )30.85 Tubular feature, internal part5,471 Tubular feature )1.65 )30.97 Tubular feature, internal part5,471 Tubular feature )0.68 )32.62 Tubular feature, intermediate part5,471 Tubular feature )1.34 )32.53 Tubular feature, intermediate part5,471 Hemipelagic mudstone )4.68 )4.96 Mudstone host rock close to tubular features5,518 Injected sandstone Well cemented, oil-bearing5,579 Injected sandstone Uncemented, oil-bearing, contains small bands5,579.1 Injected sandstone Well-cemented band, oil-bearing5,604 Stratified sand Well cemented, oil-bearing5,609 Stratified sand )3.34 )2.39 Stratified sandstone, well cemented

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detected under ultraviolet light (illumination source435 nm) using a Nikon Eclipse E600 microscope with aUV-2A filter block.

Scanning electron microscope (SEM) analyses wereperformed using an ISI ABT-55 SEM with an attachedcathodoluminescence detector (SEM-CL), operated be-tween 10- and 20-kV accelerating voltage, at magnifi-cations ranging from ·15 to ·10,000, and usingsecondary electron (SEI) and backscattered electron(BEI) modes.

Carbon and oxygen isotopic analysis was undertakenat the SUERC facility in East Kilbride (Scotland), usinga Carbonate Prep System linked with an AP2003 massspectrometer. The reproducibility of the system is±0.1& for both d13C and d18O values. All data arereported as per mil deviation from the V-PDB interna-tional standard, and appropriate internal correctionfactors were applied.

Results

Petrographic observations

Petrographic observations for the sample analysed aresummarised in Table 1. Stratified sandstones consist of70% grains, 20–25% cement, and have 5–10% porosity(Fig. 5A). The grains are fine to medium grained andconsist of 90% quartz and 10% K-feldspar and mica.Cement consists of 80% micritic carbonate, 10% pyriteframboids and 10% quartz.

Two types of injected sandstones are observedthroughout. One type was poorly cemented and heavilyoil-saturated. A second type appeared mostly moder-ately cemented and oil-saturated. The injected units havesimilar petrographic characteristics as the stratifiedsandstones and consist of 65% grains, 10% cement andhave 25% porosity. The grains were mostly angular andfractured. The cement consists of 40% quartz over-growths, 40% micritic carbonate and 20% pyrite. Pyrite

framboids predate micritic carbonate, which in turnpredates quartz overgrowths.

In several sandstone dykes and sills, bands withdiffering textural characteristics were observed. Thesebands are characterised by a drastic decrease in porosity(down to 5%), by a reduction in grain size due to thelarge amount of fractured grains, and by the diffusepresence of pyrite framboids in trails parallel to theorientation of the bands (Fig. 5B). BEI and SEM-CLobservations in these bands revealed that the extensivelyfractured detrital quartz and feldspar grains are ce-mented with differently luminescing cements (Fig. 5C,D). Petrographic and textural characteristics indicatethat these bands are deformation bands (Mair et al.2000). CL microscopy of the micritic cement in the in-jected sandstones revealed no luminescence.

The observed tubular features exhibit different sizesand shapes. The majority have a tubular shape with adiameter ranging from a few millimetres up to 2–3 cm(Fig. 6A–C). Thin sections cut perpendicular to the longaxis of the tubular features revealed concentric zones ofdifferent carbonate cements which grew towards thecentral part of the structure (Fig. 6D). The external partwas commonly characterised by clay-rich micritic ce-ment with pervasive pyrite framboids, locally formingaggregates. The internal part commonly consisted ofsparitic calcite or occasionally aragonite. The centralpart of the tubular features was commonly void, butoccasionally the cavity was filled with oil or sandstone(Fig. 6C). In some instances, the whole feature appearedcompletely oil-stained. CL microscopy revealed that theearly micritic calcite cement was dull-luminescent,whereas the later blocky and fibrous calcite filling theinternal part of the features was composed of alternatingzones of bright- and dull-luminescing calcite (Fig. 6E).No evidence of dissolution was seen in any of the sam-ples, indicating a continuous precipitation history of thecarbonate. Sections taken parallel to the long axis of thetubular features demonstrate that their diameter cangradually vary in size and that the direction of the longaxis can change at angles of up to almost 90�.

Table 1 (Continued)

Depth Sample d18O d13C Short description/comments(ft) (V-PDB) (V-PDB)

5,610 Stratified sand Well cemented, oil-bearing5,622 Stratified sand Well cemented, oil-bearing5,625 Angular concretion )2.46 )1.83 Well cemented with sparitic calcite cement5,625 Angular concretion )2.64 )2.06 Well cemented with sparitic calcite cement5,655 Angular concretion Well cemented with sparitic calcite cement5,655 Angular concretion )5.48 )7.91 Angular concretion, external part5,655.5 Angular concretion Well cemented with sparitic calcite cement5,658 Angular concretion )3.87 )0.61 Well cemented with sparitic calcite cement5,658 Angular concretion )4.95 )8.00 Angular white concretion5,730 Angular concretion )3.27 )9.04 Angular concretion, sparitic cement5,730 Angular concretion )4.07 )7.95 Angular concretion, sparitic cement5,737.2 Injected sandstone Poorly cemented, oil-bearing, contains bands5,738 Injected sandstone Cemented, oil-bearing, contains bands5,753 Injected sandstone Poorly cemented, oil-bearing, contains bands

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In rare cases the tubular features displayed moreirregular shapes and porous textures. These irregular-shaped features were entirely composed of coarse-grained sparry calcite with aragonite aciculae in theinternal parts. CL microscopy revealed that the calciteand aragonite were composed of alternating luminescingand non-luminescing zones.

Angular carbonate concretions observed distributedthroughout the mudstones of the Balder Formation

were composed of sparitic calcite and dolomite cement.These crystals were angular and fractured andcommonly showed calcite overgrowths which cementedall the crystals together. A similar type of concretion,observed in the nearby Harding Oil Field, wasinterpreted as carbonate-cemented coprolites whichunderwent different stages of diagenesis during burial(Watson 1993).

Fluid inclusions

All sandstone samples analysed revealed the presence ofmonophase primary aqueous inclusions (type A) andmonophase yellow-fluorescing primary oil inclusions(type B) within carbonate and quartz cements (Table 2).

Fig. 5 A Plane light microscope image of stratified sandstone;quartz grains are cemented by mostly micritic calcite with pervasiveframboidal pyrite, B Plane light photo-mosaic of injected sandstoneshowing deformation band in the central part (solid lines). C SEMimage on BEI mode showing compact texture of quartz grainsalong a deformation band in an injected sandstone. D Same imageseen with SEM-CL detector shows fractured detrital quartzcemented with differently luminescing quartz cement

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In the stratified sandstones, aqueous and fluorescinginclusions were observed within the intra-granular ce-ment and in the quartz fractures and overgrowths. In theinjected sandstones the inclusions were observed in thegrain fractures, tracing the rims of the quartz over-growths (Fig. 7A, B), trapped within the micritic cement

(Fig. 7C, D) and along the fragmented surfaces of thegrains in the deformation bands (Fig. 7E, F). Theobserved deformation bands reveal higher amounts offluorescing inclusions, which are mostly concentratedaround the fragmented grains and the fractures withinthe grains.

The tubular features contain abundant one-phaseaqueous inclusions as well as both one- and two-phaseoil inclusions in the carbonate cement. Oil inclusions arefar less common in comparison to the injected sandstonesamples. The micritic cements contained one-phaseaqueous inclusions and small oil inclusions in intra-crystal sites, whereas the aragonite and sparite crystalscontained larger one-phase aqueous inclusions andfluorescing one- and two-phase oil inclusions whichoccurred either within trails following crystal growth

Fig. 6 A Detail of core showing some of the tubular features(outlined by dashed lines). B Detail of one of the tubular featuresshowing concentric zones of different carbonate cements, and oilstain in internal part. C Tubular features sampled close to injectedsandstones show sparitic calcite, occasionally oil-stained, andlithified injected sandstone filling the central void part of thefeature. D Section of tube perpendicular to the long axis (planelight) showing micritic cement (M) and sparitic calcite (S). E CLimage showing dull luminescence for micritic cement and alternat-ing zones of bright and dull luminescence for sparitic calcite

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zones or within isolated populations inside the crystals(Fig. 7G, H). The size, shape, and degree of fill observedin the two-phase inclusions suggest that they are likely tobe the result of stretching within the weak carbonatecrystals (Goldstein 1986).

Isotopes

Figure 8 shows the results of the oxygen and carbonstable isotope analyses of carbonate cements associatedwith tubular features, injected sandstones, stratifiedsandstones, concretions and host mudstone sediments(Table 1). All the carbon isotope compositions havenegative values.

The few injected sandstones containing enough car-bonate 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 thetubular 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 fromtransitional zones on the most external part of thetubular features, yielded less depleted 13C values()16.8&<d13C<)13.3&) and more depleted 18O val-ues ()5&<d18O<)3.6&). The concretions, distributedthroughout the studied core interval, exhibit a moderate13C depletion ()16.9&<d13C<)0.6&) and a widerange of d18O values ()5.5&<d18O<)1.8&) whichgenerally decrease with depth. The small portion ofmicritic cement contained in the mudstone host rockshowed slight 13C depletion, whereas the 18O valuesshowed the highest depletion of all the samples in thisstudy.

Discussion

The origin of diagenetic carbonates

Broadly similar isotopic compositions for authigeniccarbonate in tubular features and the surroundinginjected sandstones suggest a common source of pre-cipitation. Cement precipitation temperatures below50 �C are indicated by the presence, in all of the samples,of abundant primary monophase aqueous and oilinclusions within the carbonate cements (Goldstein2001). This in itself does not constrain when cementationoccurred, since 50 �C is about the maximum (present-day) burial temperature experienced by the GryphonField. If the described diagenetic carbonate precipitatedfrom a marine pore fluid, with d18O around )1 to)2SMOW, (Shackleton and Kennett 1975), the calculatedrange of precipitation temperatures for the two extremed18O values of the main cluster ()3 and 0&) has a rangebetween 14 and 27 �C (Friedman and O�Neil 1977,Fig. 9). However, regional studies (Watson et al. 1995;Stewart et al. 2000) indicate that during the Palaeogene18O-depleted meteoric fluids (composition around)10&SMOW, Fallick et al. 1985) flushed the reservoirs inthe southern part of the Beryl Embayment of the SouthViking Graben. A single meteoric origin for the porefluid can be excluded, given that it would result in pre-cipitation temperatures well below 0 �C (Fig. 9). Thetemperature of 27 �C deduced for a pure marine porefluid also represents an extreme estimate, resulting in amaximum burial depth of carbonate cementation closeto 1 km (assuming a geothermal gradient of 33 �C/km;Barnard and Bastow 1991). However, it is very likelythat some mixing between meteoric and marine pore

Table 2 Summary of most representative samples containing primary fluid inclusion populations. L Liquid, V vapour, A aqueous, B oil, Pprimary

Depth(ft)

Sample Host Contents atroom temp.

Occurrence Size range(lm)

Morphology Degreeof fill

5,357 Injected sand Quartz LB P; overgrowth <3 Subrounded 100P; fractures <3 Subrounded 100

5,400.5 Irregular tubularfeature

Sparitic calcite LA P; intra-crystal site <5 Subrounded 1.00LBVB P; intra-crystal site <15 Irregular 0.75LBVB P; inter-crystal site <20 elongated 0.85

5,468 Tubular feature Sparitic calcite LA P; intra-crystal site <4 Subrounded 100LB P; intra/inter-crystal site <7 Subrounded 100LBVB P; intra-crystal site <20 Irregular 0.85

5,469 Tubular feature Micritic calcite LA P; intra-crystal site <4 Subrounded 100LB P; inter-crystal site <7 Elongated 100

5,579 Injected sandstone Micritic calcite LB P; inter crystal site <3 Elongated 1005,610 Stratified sandstone Quartz LA P; overgrowth <3 Subrounded 100

LB P; overgrowth <3 Subrounded 100LB P; fractures <3 Subrounded 100

5,622 Stratified sandstone Micritic calcite LA P; inter-crystal site <4 Subrounded 100LB P; inter-crystal site <3 Subrounded 100

5,737.2 Injected sandstone Quartz LA P; overgrowth <3 Subrounded 100LB P; overgrowth <3 Subrounded 100LB P; fractures <3 Subrounded 100LB P; bands <3 Subrounded 100

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fluids took place (Watson et al. 1995; Stewart et al.2000). Given that sand injection is thought to take placeat no more than a few hundreds metres of burial(Lonergan et al. 2000; Jolly and Lonergan 2002; Huuseet al. 2003), carbonate cementation took place prior toincreased burial of the section.

The diagenetic evolution of tubular featuresand injected sandstones

Tubular features with shapes similar to those describedhere, and of scale varying from centimetre to decimetre,have been recognised in a range of different geologicalsettings where they have been interpreted as modern andpalaeo-carbonate seep structures (Kulm and Suess 1990;von Rad et al. 1996; Aiello et al. 1999; Conti and Fontana1999; Stakes et al. 1999; Kenyon et al. 2002; K. Campbell,personal communication). In all these cases, the authi-genic carbonate was inferred to have precipitated inconduits along which hydrocarbon-rich fluids, mostlymethane, were seeping close to the subsurface. In thepresent study also, this hypothesis is confirmed by geo-

chemical and petrographic analyses. The significant 13Cdepletion of cement phases observed within the tubularfeatures strongly indicates a contribution of carbon fromhydrocarbons. This suggests microbially mediated oxi-dation coupled with sulphate reduction during burial(Ritger et al. 1987; Suess andWhiticar 1989; Boetius et al.2000). Isotopic results, petrographic characteristics andthe absence of a chemosymbiotic fauna reflect the pre-cipitation of cement within buried sediments, below theseawater interface. The local presence of aragonite, theprecipitation of which is favoured at high SO4

2) concen-trations and Mg2+/Ca2+ ratios (Burton 1993), indicatesseaflooror close-subsurface conditions (Aloisi et al. 2002).This supports the idea that the tubular feature-richintervals were close to the seafloor during their formation.The fact that these features are present only in the upperFrigg Formation could indicate that these shales were atthat time being deposited along with the precipitation ofthe authigenic carbonate (i.e. described tubular features).The mineralogical changes in the concentric zones clearlyindicate different growthphases of carbonate cement in anenvironment which was constantly supporting the pre-cipitation of carbonate cement. This is also confirmed byCL microscopy which showed zoned carbonate cements,suggesting gradual precipitation of carbonate cementwhich accompanied hydrocarbon-rich fluid escapes (Jonket al. 2003b; Mazzini et al. 2003). The presence of fluo-rescing oil inclusions in the carbonate cement observed inintra- and inter-crystal sites, combined with the presenceof substantial oil staining infilling voids, indicates thatpetroleum seepage was ongoing at shallow burial. Asthin cemented sandstones occasionally infill the internalcavities of the tubular structures, the non-cemented voidswere likely to be later exploited during a phase of sandinjection. The possibility that hydrocarbons exploitedpreviously existing, buried Lamellibranchia tubewormstructures or bioturbation burrows cannot be discarded.However, no evidence of mucus lining, internal structure

Fig. 8 Cross-plot of carbon(13C) and oxygen (18O) stableisotope compositions forcarbonate cements

Fig. 7 A Plane light microscope image of quartz grains in injectedsandstone with small amount of micritic cement and numerousquartz overgrowths. B UV microscopy shows fluorescing oilinclusions tracing the rims of the quartz overgrowths (open arrowsindicate fluorescing inclusions). C Plane light image of quartzgrains surrounded by framboidal pyrite aggregates, organic matterand micritic cement. D UV microscopy shows fluorescing oilinclusions (open arrows) around the quartz grains and in the inter-,intra-crystal sites within the micritic cement. E Plane light image ofquartz 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 inthe internal part of a tubular feature; brown two-phase oilinclusions (closed arrows) are visible inside the calcite crystals andat the inter-crystal sites. H UV microscopy shows fluorescing oilinclusions (open arrows) in the calcite cement

b

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or branching in the structures was observed. The materialfilling these structures would have had to be removed andreplaced by hydrocarbon-derived authigenic carbonate.Alternatively, if these degassing conduits formed in thesubsurface soft sediments, the change in size and orien-tation of the conduits suggests that sedimentary structuresor discontinuities within the mudstone host unit con-trolled the gas distribution in the sediment and the shapeof the conduits. The lower oxygen and higher carbonvalues recorded for the samples drilled from the externalparts of the tubes suggest possible mixing with the mud-stone host rock (which is typically less 13C-depleted andmore depleted in 18O).

The injected sandstones show isotopic characteristicssimilar to the carbonate tubular features, suggesting thatsimilar petroleum fluids seeped from the reservoir. Itseems realistic to consider that petroleum (oil and gas)filled the injected sandstones soon after the injectionprocess, and was still present after the burial of thesection. This is evidenced and supported by the occur-rence of primary petroleum inclusions within carbonatecement which formed at shallow burial (well below1 km). Moreover, the presence of primary petroleuminclusions in both earlier (micritic cement and quartzfracture-fills within deformation bands, Jonk et al.2003a) and later (quartz overgrowths which formedclose to the present-day burial depth, Worden andMorad 2000) diagenetic cements suggests that petroleummay have entered the sandstones during the injectionprocess and remained until the present-day. The nega-tive carbon isotopic values for carbonate cements withinthe injected sandstones and the significant amounts ofoil inclusions suggest that petroleum was activelysourcing bicarbonate carbon through microbial oxida-tion of hydrocarbons (Irwin et al. 1977) to the precipi-tating calcite. This hypothesis is also supported bymeasurements performed at petroleum seepage sites in

the northern Gulf of Mexico (Roberts et al. 1990;Roberts and Aharon 1994), where results indicate thatdiagenetic carbonates with comparable d13C depletionoriginate from the microbial degradation of hydrocar-bons ranging from crude oil to biogenic methane. In thestudy described here, the biogenic or thermogenic originof methane remains uncertain.

Model

Crosscutting relationships between the tubular featuresand the surrounding injected sandstones indicate thatinjected sandstones postdated the degassing features.The formation of the tubular features occurred during afirst phase in the shallow subsurface where gas and oilfrom the reservoir migrated along fractures and faults(Fig. 10A). Seepage of gas in the shallow subsurfaceoccurred in the uncompacted hemipelagic sediment. Theformation of authigenic carbonate deposits on the sea-floor cannot be excluded, but limitations of a core-basedstudy do not allow the laterally extensive samplingwhich would be required to prove this process. During asecond phase, sandstone dykes and sills were generatedby sand remobilisation at shallow depth from the mainreservoir in the Balder Sandstones (Fig. 10B). Theseunits crosscut the seepage features, which were overlyingthe reservoir. Precipitation of authigenic carbonatewithin both degassing features and injected sandstoneswas facilitated by supply of bicarbonate through oxi-dation of petroleum (both methane and oil). It is notpossible to establish whether oil was present during theinjection phase (although it is certain that petroleummoved into injected sandstones very soon after theirformation) but it appears that injected sandstone unitswere used as pathways for oil migration from the res-ervoir up to shallow depth (Fig. 10C). Several injectedsandstones are located along the conduit-rich horizons.As comparable yellow-fluorescing inclusions were ob-served in all of the samples, it is likely that petroleumfluids migrated from the reservoir through the hostmudstones, inducing the precipitation of authigenic

Fig. 9 Plot indicating d18OSMOW for pore-fluid composition andtemperature of precipitation with curves of two extreme d18Ovalues for carbonate cements. Arrows indicate the range oftemperature precipitation for pure meteoric pore fluids, puremarine pore fluids, and mix of marine/meteoric pore fluids

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carbonate in the tubular features and in the injectedsandstones (Jonk et al. 2003b; Mazzini et al. 2003).Precipitation of authigenic carbonate in both featuresfossilised the petroleum escape pathway and highlightsthe active role which petroleum plays in the precipitationof authigenic carbonate.

Conclusions

1. Combined petrographic and geochemical analysesindicate that petroleum leakage from the reservoiroccurred in the shallow subsurface in the southernpart of the Gryphon Oil Field. Zoned authigeniccarbonates precipitated along degassing conduitsprovide evidence for a rare example of palaeo-seep-age above a hydrocarbon reservoir.

2. Tubular degassing features and injected sandstonesboth formed during shallow burial. Analyses showthat petroleum seepage occurred during the earlyphase of formation of the tubular degassing features,and continued during the later phase of sand injec-tion. Both those features exhibit oil saturation and/ora substantial amount of oil inclusions within the ce-ment. The oil inclusions would be consistent with amodel in which hydrocarbons enhanced the injectionprocess, but we cannot prove this.

3. Injected units and degassing conduit-rich horizonswere likely to be exploited by subsequent phases ofoil leakage, as oil inclusions and oil stains currentlyoccur in both these features.

Acknowledgements This paper is published with the permission ofKerr McGee North Sea Ltd. and the Gryphon Field partners.The views and opinions expressed by the authors may notalways necessarily reflect the standpoint of the Gryphon Fieldpartners. The authors would like to thank Catherine Pierre, KevinPurvis and John Woodside for their critical review of the manu-script and helpful ideas for its improvement. Tony Fallick andAndrew Tait (SUERC) are thanked for their support duringisotopic analyses.

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