Hydrocarbon potential of the Visean and Namurian in thenorthern Dutch offshore

M. M. TER BORGH*, W. EIKELENBOOM & B. JAARSMA

EBN BV, Daalsesingel 1, 3511 SV, Utrecht, The Netherlands

M.t.B, 0000-0002-1698-2411*Correspondence: marten.borgh-ter@ebn.nl

Abstract: Following the play-opening successes of the Breagh and Pegasus gas fields, we evaluated the poten-tial of the Visean and Namurian (Carboniferous) petroleum plays in the northern Dutch offshore. This evalua-tion incorporated seismic and well data from the Dutch, British and German North Sea sectors. The abundanceand thickness of reservoir-quality Visean–Namurian sandstones was found to increase from Breagh towards theNE. Visean–Namurian coals and shales are considered promising source rocks to charge these reservoirs in theDutch Central Graben (DCG) and Step Graben (SG). The presence of a mature Paleozoic source rock in the SGand DCG is supported by hydrocarbon shows and vitrinite reflectance data. In the southern E and F blocks,charge may also occur laterally from Upper Carboniferous Westphalian coals. A regional post-well analysisshowed that the Visean and Namurian plays are virtually untested in the Dutch northern offshore. Two testswere positive but had high N2 contents, onewas negative, while 10wells were drilled off-structure and are there-fore considered invalid tests of this play. Hence, it is concluded that the Visean and Namurian in the northernDutch offshore have significant hydrocarbon potential.

Production of hydrocarbons from Carboniferousreservoirs in the Southern North Sea comes pri-marily from the Westphalian. The discovery anddevelopment of gas fields with reservoirs in thepre-Westphalian, such as the Visean Breagh Field(Fig. 1) (McPhee et al. 2008) and the NamurianPegasus Field, triggered new interest in the hydro-carbon potential of the Visean and Namurianin the Southern North Sea and Mid North SeaHigh area. In this study, a regional analysis ofthe hydrocarbon potential of this stratigraphic inter-val is presented focusing on the Dutch offshore,while incorporating data from the UK and Germanoffshore.

To assess the viability of the Visean and Namur-ian plays, well results were analysed initially.Next, well and seismic data were used to constraindepositional trends and palaeogeography, and,based on this analysis, the distribution of potentialreservoirs was established. To further quantify thereservoir potential, core-plug measurements areused. To establish the chances of hydrocarboncharge and migration, shows of hydrocarbons inexisting wells are summarized, and the presenceand maturity of source rocks is estimated fromseismic and well data. A recently developed struc-tural framework for the area (ter Borgh et al. thisvolume, in press) is used to further assess reservoirdevelopment, source-rock presence and maturation,and trap formation.

Geological setting

During the Early Carboniferous, the study area waslocated on the southern margin of the continent Laur-ussia, which had formed during the Ordovician–Silurian collision of three older continents duringthe Caledonian Orogeny: Avalonia, Baltica andLaurentia (e.g. Ziegler 1990; Smit et al. 2016). Dur-ing the Early Carboniferous, Laurussia was converg-ing with Gondwana, located to the south ofLaurussia, which resulted in significant extensionon Laurussia’s southern margin due to either back-arc extension (e.g. Leeder 1988), continental escape(e.g. Maynard et al. 1997) or a combination of both(e.g. Coward 1993). This caused a roughly east–west-orientated basin to form between present-dayIreland and Poland.

Sediment influx into the basin occurred from theCaledonides in the north (e.g. Collinson 2005). Inthe northern part of the basin, fluvial and paralicconditions prevailed, while greater water depthsdeveloped in the central part of the basin. Thestudy area is located at the boundary between thesetwo domains (Smit et al. 2016). The London–Brabant Massif forms the southern margin of thedeep part of the basin (Ziegler 1990).

Extension was distributed over a wide area, andresulted in a large-scale alternation of highs andlows, with widths of the order of tens of kilometreseach. The highs in many cases have a core that

From: MONAGHAN, A. A., UNDERHILL, J. R., HEWETT, A. J. & MARSHALL, J. E. A. (eds) Paleozoic Plays of NW Europe.Geological Society, London, Special Publications, 471, https://doi.org/10.1144/SP471.5© 2018 The Author(s). This is an Open Access article distributed under the terms of the Creative CommonsAttribution License (http://creativecommons.org/licenses/by/3.0/). Published by The Geological Society of London.Publishing disclaimer: www.geolsoc.org.uk/pub_ethics

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consists of a Caledonian granite (Donato et al. 1983).The Elbow Spit Platform (ESP), located in the north-ern Dutch offshore (Figs 1 & 2), is an example ofsuch a high. At its northern side, it is bounded bythe North Elbow Basin, where subsidence rateswere higher than on the ESP, but not high enoughfor significant water depths to develop as sedimenta-tion rates exceeded subsidence (Figs 2 & 3). As aresult, sedimentation extended onto the ESP. Sedi-mentation also occurred south of the ESP, butsediment influx during the Visean was insufficientto fill this part of the basin completely (ter Borghet al. this volume, in press) and significant waterdepths developed there, except on intra-basinalhighs where carbonate platforms formed (Kombrinket al. 2010b; van Hulten 2012).

Continental collision of Laurussia andGondwanafinally occurred during the late Visean–Westphalian,leading to the Variscan Orogeny. Extension ceasedand inversion of the basin occurred, causing foldingand erosion of the basin fill (Ziegler 1990). LateCarboniferous–Early Permian volcanism was accom-panied by additional uplift and erosion. Inversion andthermal uplift resulted in the formation of the BasePermian Unconformity (BPU). During the Permian,sedimentation resumed following a 40–60 myrhiatus with the deposition of Upper Rotliegendreservoirs, and Silverpit and Zechstein Formation

seals (Geluk 2007). The subcrop at the BPU in thestudy area varies from Lower Carboniferous toLower Permian.

During the Mesozoic, the Central Graben sys-tem formed, leading to the formation of theDutch Central Graben (DCG) and the Step Graben(SG) in the study area (Fig. 1). Extension alongthese structures has been proposed to have startedas early as the Devonian, but recent data suggestotherwise (ter Borgh et al. this volume, in press).Extension led to regional subsidence and progres-sive burial of the Carboniferous, but subsidencewas interrupted during the Middle Jurassic, whenuplift centred at the triple junction of the three riftsegments of the Central Graben system led to the for-mation of the Central North Sea Rift Dome (Ziegler1990; Underhill & Partington 1993). Extension andsubsidence subsequently resumed. Extension ceasedin the Early Cretaceous, but post-rift subsidenceallowed for the deposition of up to 2 km of Cenozoicdeposits.

As a result of the post-Carboniferous develop-ment of the area, the present-day burial depth ofCarboniferous deposits varies from about 2.2 kmon the crest of the ESP to over 9 km in the DCG.As a result, reservoir quality may be expected torange from very good to very poor, and source-rockmaturity from immature to over mature.

Fig. 1. Overview of wells and gas fields discussed in this paper. All fields are shown where the gas column extendsinto Visean or Namurian reservoirs. In fields with Namurian reservoirs, the gas column commonly extends into theWestphalian. Late Jurassic–Early Cretaceous structural elements (modified after Doornenbal & Stevenson 2010) areshown. ADB, Anglo-Dutch Basin; DCG, Dutch Central Graben; ESP, Elbow Spit Platform; ORB, Outer RoughBasin; SG, Step Graben; SPB, Silver Pit Basin; TEG, Tail End Graben.

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Fig. 3. Diagram illustrating the structural geology and play elements of the Visean and Namurian in the Mid NorthSea area. The Elbow Spit Platform is an example of a high (C), while the North Elbow Low is an example of anoverfilled basin (D). South of the study area, carbonate platforms are present on intra-basinal highs such as theGroningen High (A) (Kombrink et al. 2010b; van Hulten 2012). Between the highs, basins were present wheresubsidence exceeded sedimentation (B).

Fig. 2. Structural elements during the Visean. UK sector after Milton-Worssell et al. (2010), Arsenikos et al. (2015)and Kearsey et al. (2015). AFR, Auk-Flora Ridge; DH, Dogger High; ESP, Elbow Spit Platform; FG, Farne Granite;NDB, North Dogger Basin; NEB, North Elbow Basin.

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Stratigraphical framework

This publication focuses on the two Carboniferousstages predating the Westphalian: the Visean andthe Namurian (Fig. 4). The stratigraphic subdivisionof the Carboniferous commonly used in Western

Europe is distinct from the international system(Kombrink et al. 2010a) (Fig. 4). The subdivisionof the Carboniferous in The Netherlands has histori-cally been based on lithostratigraphy, not chrono-stratigraphy (Kombrink et al. 2010a). This has asignificant impact as many formation boundaries

Fig. 4. Stratigraphic chart for the Visean and Namurian of the Mid North Sea area. Well penetrations are shown.Colours in the substage column refer to the maps in Figure 5.

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within the Carboniferous are diachronous; the baseof the Yoredale Formation, for instance, is knownin northern England to range from the earlyBrigantian to the Pendleian (Waters et al. 2007).To predict where reservoir rocks and source rockswere deposited, it is necessary to reconstruct the dep-ositional system and, hence, to know which sectionsare age equivalent. Where available, biostratigraphicconstraints have therefore been used to correlatebetween wells, using the results from the study bySchroot et al. (2006) as a starting point. The resolu-tion of biostratigraphy during this time interval is lim-ited, however, and significant uncertainties remain.

Data and methods

Seismic and well data

2D and 3D seismic data from various vintages wereused. The DEF survey, a 7950 km2 3D multiclientsurvey, covers the Dutch D quadrant and the south-ern E and F quadrants (Fig. 1). The northern E andF, and the A and B quadrants are partly covered bypublicly available 3D surveys acquired in the periodbetween 1994 and 2006. 2D data were used in placeswhere no 3D data were available: the entire studyarea is covered by the North Sea Renaissance(NSR) 2D multiclient survey, which consists of agrid of regional seismic lines shot in the NW–SEand NE–SW directions, with a spacing betweenlines of 5.3 km. The survey was acquired between2005 and 2010, and the Dutch part of the surveyhas since become public. Seismic interpretationwas carried out in the time domain and the non-SEGY seismic convention was used.

For the Dutch part of the area, data from over 60wells acquired from NLOG (http://www.nlog.nl/)were used for seismic interpretation, 14 of whichencountered the Visean and/or Namurian (Fig. 1).In the UK sector, data from eight public wells thatencountered these stages were used (Fig. 1). Dataavailability from the German sector was limitedto a well that was formerly located in the Dutchsector (B10-01) and a well published in the South-ern Permian Basin atlas (A-09-01: Kombrink et al.2010a). The wells were tied to seismic data usingcheckshots.

Analysis of well results

To assess the hydrocarbon potential of the Viseanand Namurian, the results from existing wells inthe northern Dutch offshore were evaluated withthe aim of establishing whether a particular wellcan be considered a valid test of the Visean andNamurian plays, and, if so, whether the result waspositive or negative. This evaluation consisted offour steps:

(1) The presently available seismic data were usedto establish whether a valid trap is present at thewell location. If it is clear from the seismic datathat no trap is present, the well is considered aninvalid test. This commonly occurswhen awelltargeted a closure at another level; if the welltargeted a closure at the Chalk level, forinstance, no structure needs to be presentwithinthe Visean. Another common reason for aninvalid test due to the absence of a valid trapis that old 2D data were used.

(2) Establish the presence of reservoir from welldata. This was considered positive if enoughreservoir rock is present within the strati-graphic interval so that if gas bearing, thewell would have been a technical success.

(3) Evaluate the presence of a seal.(4) Finally, the presence of hydrocarbons (‘charge’)

was evaluated. If enough hydrocarbons are pre-sent to consider thewell a technical success, thewell was considered a valid positive test.

If the test is considered valid (see step 1) and eitherreservoir, seal or charge is absent or ineffective, thewell was considered a valid negative test.

Lithological classification

To assess the source-rock and reservoir potential ofthe Visean and Namurian, a lithological classifica-tion was performed for all selected wells based onwireline logs, including the gamma-ray and soniclogs. Cut-off values to constrain lithological classeswere defined empirically by comparing log response,mud logs, and previous interpretations by CollinsonJones Consulting (1997) and Schroot et al. (2006).An overview of the classes and cut-off values usedis given in Table 1. The lithological classificationwas checked against cuttings descriptions if available.

Porosity and permeability measurements

To assess the reservoir potential, an analysis ofporosity and permeability data was carried out. ForDutch wells, core-plug measurements were acquiredfrom reports and data available on http://www.nlog.nl/. For the UK wells, data from publicly availablewell reports were used. To each measurement, theresult from the lithological classification was addedin order to establish the reservoir properties foreach lithological class.

Results

Well results

As the number of wells penetrating the Visean andNamurian in the northern Dutch offshore is low,only two play types are distinguished. In principle,

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it would be possible to make a more detailed classi-fication but this would not yield statistically mean-ingful results:

• The Visean clastics play: reservoirs in the ElleboogFormation or Yoredale Formation, sourced fromVisean coals, Visean–Namurian basinal shales,Westphalian coals or Zechstein Group sourcerocks, and trapped below the Permian SilverpitFormation or Zechstein Group deposits.

• The Namurian clastics play: source and sealas above, but with a Namurian (post-Yoredale)reservoir.

Visean play. Five out of six wells penetrating theVisean in the study area are considered invalidtests of the Visean play as they did not drill validstructures, results from the sixth well are inconclu-sive. This is not unexpected, as none of these wellstargeted the Visean. In addition to this, most wellswere drilled in a period when 3D seismic datawere not widely available; the most recent wellthat encountered the Visean was drilled in 1990

(E02-02), the other wells were drilled between1972 and 1983. In most cases the presently availableseismic data show that no structure is present at thewell location, whereas vintage 2D seismic data mayhave suggested that a closure was present.

All wells contained at least some layers with res-ervoir potential (Table 2). Rocks with sealing poten-tial were present in most cases. In four wells, sealingwas provided by relatively low-risk Silverpit shales.In one case, an intra-Carboniferous seal may havebeen present but as a trap was absent in this case, itis unclear whether the seal was effective. In wellE02-01, the Carboniferous was overlain by Chalkdeposits. The Chalk is considered a riskier sealthan the Silverpit and no detailed analysis was car-ried out to assess its sealing potential here. Minoror doubtful shows were found in two wells. Theabsence of shows in the other wells should not beused to conclude that charge was absent; as trapswere absent, no trapping of hydrocarbons would beexpected to occur in the first place.

Namurian play. Eight wells in the study area encoun-tered the Namurian (Table 3). Similar to the findingsfor the Visean, six of these wells are considered inva-lid tests as presently available seismic data show thatthe wells did not drill a valid structure. In two cases,accumulations were found: the Tulp and Lelie fields(Fig. 1), which are likely to have been charged fromdownthrown Westphalian Coal Measures and possi-bly the Namurian. As all play elements worked andgas was tested at economic flow rates, these twowells are considered technical successes and validtests. It should be noted, however, that significantamounts of N2 were encountered in both wells, ren-dering these discoveries uneconomic.

Further north, where no Westphalian CoalMeasures are expected, well A15-01 (Fig. 1) drilledonly a thin section of Namurian rocks but the overly-ing Zechstein carbonates were found to be gas bear-ing, with oil shows. The interval was tested and aflare was lit, but production rates were low. Thetest was adversely affected by a poor cement job,which makes it likely that communication existedbetween the tested carbonates and previously tested

Table 1. Cut-off values used in lithologicalclassification

Gammaray

(GR, API)

Sonic (DT, µs/ft)

> ≤ > ≤Carbonate 60 57–68*Sandstone 60 57–68*Coal 100Shaly sandstone 60 100 68Marl 60 100 57–68*Shale 100 68Igneous rock From mud log/operator composite

log

To take into account the effects of depth of burial on the seismicvelocity, the values marked with an asterisk were made depthdependent. At depths lower than 3000 m, a value of 68 µs/ft wasused. In wells 42/13- 2 and 42/10b- 2, a value of 60 µs/ft wasused below 3000 m measured depth (MD), and a value of 57 µs/ftbelow 3250 m MD. In wells 39/07- 1, A-09-01 and B10-01, avalue of 65 µs/ft was used below 3000 m MD.

Table 2. Well results for the Visean.

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water-bearing intervals. Nitrogen was present, butnot in problematic quantities (16%). Although itremains unclear what source the gas was derivedfrom, the test proves that a mature Paleozoic sourcerock is present. Candidates are the Visean andNamurian (Elleboog, Klaverbank and Yoredale for-mations), the Zechstein itself, and the Devonian.

Reservoir: porosity, permeability andnet-to-gross ratios

Visean. To constrain the distribution of reservoirrocks, the results from the lithological classificationwere summed for each stratigraphic interval, andthe results were displayed in map view (Fig. 5).The results show in broad terms that most formationsbecome more sand-rich towards the north. The char-acteristics of core plugs taken from intervals classi-fied as sandstone or shaly sandstone are shown inFigure 6, confirming the presence of reservoir qual-ity sandstones within the Visean and Namurian;based on this result, intervals classified as sandstoneare considered net reservoir. Intervals classified asshaly sandstone can be considered upside. Basedon the data, no clear lower limit for the reservoirpotential can be given; the deepest well with signifi-cant amounts of data, E12-04-S2, shows decentporosities (average 12.7%, σ = 3.0) at 3.8 km. Thereservoir potential of the Visean is probably higherthan the core-plug measurements suggest; channel-fill sandstones are commonly considered the bestVisean reservoirs and, although indications forsuch sandstones are present in all wells penetratingthe Farne Group in the northern Dutch offshore,they have only been cored in well E02-01. Porositiesas high as 25% (average 12.9%, σ = 4.1) and perme-abilities as high as 269 mD (average 42.7 mD) weremeasured here (Fig. 6).

Net-to-gross ratios vary per interval (Fig. 5). Ingeneral, proximal deposits have greater amounts ofsand, meaning that net-to-gross ratios increasetowards the north/NE. However, reservoir rocks

may occur in all parts of the system. Figure 5shows a map with lithological characteristics forthe first 100 m below the BPU, giving an indicationof net-to-gross ratios for closures at the Base Perm-ian level.

Namurian. Sandstone intervals with a sharp base andtop, and little internal variation on log data (‘blocky’sandstones) are found throughout the NamurianKlaverbank Formation in the study area. These sand-stones resemble producing Westphalian KlaverbankFormation reservoirs from the D and southern Equadrants (Fig. 4); the depositional environmentsare similar but, as progradation progressed fromnorth to south, they differ in age. The net-to-grossratio of this stratigraphic interval is generally high(c. 45%: Fig. 5a); not just in the E12 quadrant butalso further north.

Visean–Namurian source rocks

In the British and German offshore. Visean andNamurian coals are predominantly found in the Scre-merston Formation. The Dutch equivalent, the Elle-boog Formation, has been encountered in three wellsin The Netherlands: E02-01, E02-02 and E06-01.Coal streaks recognizable on logs have been foundin well E02-02, and thin coal seams below the reso-lution of log data have been identified in cores andmud logs from wells E06-01 and E02-01. Althoughthe number of wells is limited, the coal content of theScremerston Formation appears to increase north-wards (Fig. 5c): well 39/07- 1, located less than1 km across the median line from the A quadrant,contains 23 m of coal (Figs 7 & 8), but this shouldbe considered a minimum thickness as the base ofthe Scremerston Formation was not reached in thiswell. German well A-09-01, located 13 km acrossthe border, captures a complete Scremerston section(Kombrink et al. 2010a) (Figs 7 & 9); proportion-ally, it has a similar amount of coal (14%) but,

Table 3. Well results for the Namurian.

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Fig. 5. (a)–(d) Palaeogeographical charts and lithological statistics, see also Figure 4. (e) Lithological statistics forthe first 100 m below the Base Permian Unconformity (BPU), showing that the chances of encountering sandstone inthe Visean or Namurian below the Silverpit Formation and Zechstein Group seals are good. Note that not all wellsrepresent full penetrations of a given interval; see Figures 7–9. UK palaeogeography after Kearsey et al. (2015; thisvolume, in review); UK structures after Arsenikos et al. (2015). ESP, Elbow Spit Platform; NDB, North DoggerBasin; NEB, North Elbow Basin.

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because the formation is completely penetrated, thetotal amount of coal encountered is greater (30 m).

In well 39/07- 1, the presence of coals is accom-panied by a typically high-contrast seismic facies.This facies can be mapped a small distance into theDutch offshore, but cannot be continued across aWNW–ESE-trending normal fault south of thewell location that downthrows the Visean (Fig. 2).It may be the case that deposition and preservationof the coals is fault-controlled, but the downthrownfault block does not appear to be imaged on the seis-mic data covering this area. Further west, indicationsfor the presence of coals are given by NSR line32294, which has a better imaging quality at thesedepths (Fig. 10); on the ESP, the seismic faciesshows only moderate contrast, but further northand up to the German border the contrast increases(Fig. 10). In the continuation of the line, 13 km fur-ther to the NE, the coal-bearing well A-09-01 islocated (Fig. 1). Altogether, these observations arecompatible with the presence of coals in the regionnorth of the ESP, although the higher contrast mayalso result from lithologies other than coal.

Coals have also been encountered in the YoredaleFormation: 4 m in 39/07- 1, 3 m in well A-09-01,4 m in well A16-01, 0.3 m in A14-01 and 2.7 min E06-01. The same is true for the Namurian:wells 39/07- 1, B17-04, E09-01, E10-03, E12-02,E12-03 and E12-04-S2 all contain between 1 and3 m of coal. The estimates given are conserva-tive as they only take into account coal seams thatare thick enough to be distinguishable on thesonic log.

Maturity measurements

The available well data are of limited use for assess-ing maturity as it primarily covers the present-dayhighs (Fig. 1), and not the lows where source rockshave been buried to greater depths and hydrocarbonkitchens are expected. The base of the Carboniferousis located at approximately 2000 m true verticaldepth (TVD) in well E02-01 and at 2200 m in wellE06-01, while the Carboniferous is locally buriedup to depths of more than 5500 m in the SG, andto even greater depths in the DCG.

Fig. 6. Porosity and permeability measurements from Visean and Namurian intervals classified as sandstone or shalysandstone. N = 328. Data are from wells A14-01, A16-01, B10-01, E02-01, E06-01, E12-02, E12-03, E12-04-S2, 43/02- 1 and 42/13- 2. Note that measurements below the detection limit are plotted at the detection limit. (a) porositydistribution; (b) porosity–permeability plot.

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The only well that can be considered representa-tive of the present-day lows (i.e. the SG and DCG) interms of maturity is well B17-04, where maturecoals were found. Palynological dating suggests aNamurian (Pendleian–Arnsbergian) age (Cutler &Darlington 1990), and vitrinite reflectance datashow that the coals have reached the peak gas win-dow (1.4%Ro).

Maturity data from the present-day highs showthat source-rock-bearing intervals are presently inthe late oil–early gas window. In well A14-01, avalue of c. 0.74%Ro was measured at around2850 m and well 39/07- 1 shows a value ofc. 0.8%Ro at 3500 m. In well 38/16- 1, the vitrinitereflectance increases from 0.75 to 1.00%Ro overan interval of 200 m. A similar gradient is apparentin well 41/24a- 2. The measurements from wellE06-01 do not display any relationship with depth;vitrinite reflectances vary around 1.0%Ro. Thismay result from the (local) occurrence of igneous

intrusions near this well, which could have led to alocal increase in temperature.

Geological evolution and palaeogeography

During the Early Carboniferous, the northern Dutchoffshore experienced siliciclastic influx from thenorth. The region was subject to lithosphere-scaleextension, leading to an alternation of highs andlows (Fig. 3). A major facies boundary traversedthe E and F quadrants, roughly trending WNW–

ESE (Figs 2 & 5). To the north of the boundary,paralic conditions prevailed and to the south of itpredominantly deeper-water conditions.

The facies boundary was structurally controlledand coincided with a major normal fault. North ofthe fault, a long-lived high was present: the ESP(Figs 2 & 5). The facies boundary represents thearea where sediment influx and subsidence were

Fig. 7. Well correlation panel, Visean, Dutch offshore. The location is shown in Figure 5. Red denotes igneousrocks. Two columns with biostratigraphy are given: available data are shown in the first column, the resultinginterpretation (which is also used in Fig. 5) is in the second column. Measured depth is used as the vertical scale. Allwells are vertical, meaning that the difference between true vertical depth and measured depth is negligible.

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roughly in balance. North of the boundary, sedimentinflux was higher than subsidence, leading tooverfilled basins; south of the boundary, subsidencewas higher than sediment influx, leading to starvedbasins (Fig. 3). Seismic data, however, indicatethat the Lower Carboniferous and Devonian alsothicken north of the ESP, and this is interpreted toresult from the presence of the North Elbow Low(Figs 3 & 10).

Although the boundary between deep water andshallow water is thought to have existed throughoutthe Visean (Fig. 5), fluctuations of relative sea levelcaused the overfilled area to drown episodically,establishing shallow-water marine conditions, fol-lowed by an infilling of the accommodation space

by fluvial processes. On the ESP, this led to a cyclicalternation of shallow-marine carbonates and fluvio-deltaic clastic sediments, including back-swampdeposits and coals: the so-called Yoredale cycles(e.g. Waters et al. 2007). The Yoredale Formationis best known for this type of cyclicity but similarcycles can be observed in the older formations.These short timescale sea-level fluctuations wereaccompanied by steady regional tectonic subsidence,allowing for the preservation of sediments.

Towards the north, depositional environmentswere progressively more proximal, as can be infer-red from a decrease in the amount of carbonate,and an increase in clastics and coals (Fig. 5). Carbon-ate beds are present at least as far north as well

Fig. 8. Well correlation panel, Visean, UK offshore. The location is shown in Figure 5.

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39/07- 1, however, suggesting that the entire studyarea experienced episodic drowning. An alternativeexplanation for the presence of these beds that cannotbe ruled out at present is that they formed in a lacus-trine setting.

Courceyan–Chadian: Tayport andCementstone Formation

Courceyan–Chadian (Tournaisian–lowermost Visean:Fig. 4) deposits have been encountered in theDutch northern offshore in wells E06-01, E02-01and, possibly, in well E02-02, for which no biostrati-graphic constraints are available. The oldest depositsfound are fluvial and playa lake deposits from theTayport Formation (Old Red Group); the majorityof the Old Red Group, including the lower partof this formation, is Devonian in age, but sedimen-tation continued into the Tournaisian (Early

Carboniferous) (Cameron 1993; van Adrichem Boo-gaert & Kouwe 1993–97) (Fig. 4).

The Tayport Formation is covered conformablyby the sediments of the Cementstone Formation,which is characterized by metre-scale alternationsof carbonates and fine clastic sediments, representa-tive of deposition in an alluvial-plain to marginal-marine flat environment that was affected by peri-odic desiccation and fluctuations in salinity, in asemi-arid climate (e.g. Waters et al. 2007). In theUK onshore, the occurrence of cementstone faciesis commonly limited to troughs associated with(half-) graben; on the highs, the laterally equivalentcornstone facies is developed (Waters et al. 2007).As the Tayport Formation can be considered tohave been developed in the cornstone facies (Waterset al. 2007), it cannot be ruled out that the TayportFormation and Cementstone Formation are laterallyequivalent with the boundary between the two for-mations being diachronous.

Fig. 9. Well correlation panel, Namurian, Dutch offshore. The location is shown in Figure 5.

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Fig. 10. Seismic section across the North Elbow Basin. The Visean Elleboog Formation (see Fig. 4) has a high-contrast seismic facies that is likely to have been caused by thepresence of coals. The location is shown in Figure 1. Public seismic line NSR32294. TWT, two-way travel time.

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Owing to the limited well penetrations in theDutch offshore, little is known about the directionof sediment transport but it seems likely that the sedi-ment source area was located in the north, as hasbeen inferred for the rest of the Visean. It is likelythat local palaeocurrents were affected by tectonics,aligning to the axes of (half)graben. As only verylimited well data are available for this stratigraphicinterval in the Dutch sector (Fig. 7), little is knownabout the basin structure during this period. Localhighs may have existed on which no depositionoccurred or, in the case of sufficient sediment influxand accommodation space, fluvial and/or playa lakedeposits may have been deposited. A transition todeeper-marine conditions further south and a gradualtransition to more proximal facies to the north maybe inferred.

Arundian–Holkerian: lower part of theElleboog Formation

During the Arundian–Holkerian, deposition occurredin a fluvial to paralic setting; rivers deposited thickstacked channel fills, whilst shales and carbonateswere being deposited in areas experiencing a marineinfluence (Cameron 1993; van Adrichem Boogaert& Kouwe 1993–97).

We interpret the thick sand bodies at the baseof the Elleboog Formation in wells E02-01 andE02-02 as representing a more distal equivalent ofthe more massive sandstones of the Fell Formationof the UK offshore (Cameron 1993). The north–south proximal–distal trend is further illustrated bysediments encountered in well E06-01, which weredeposited close to the basin edge (Fig. 5d), wherecarbonate beds appear, alternated with shales andblocky sandstones. This alternation is interpreted tobe similar to the cyclicity observed in the Asbian–Pendleian Yoredale Formation. It is hard to placethis well in the standard lithostratigraphic nomencla-ture (van AdrichemBoogaert &Kouwe 1993–97); inThe Netherlands, it is commonly placed in the Elle-boog Formation, but the presence of carbonate bedsis at odds with the definition of this formation. Thisis due to its position close to the platform edge; thecurrent lithostratigraphic framework works betterfor deposits in a more proximal setting.

Asbian: upper part of the Elleboog Formation

Asbian deposits on the ESP are generally character-ized by an alternation of sandstone, shale and car-bonate, interpreted to have been deposited in aparalic setting, and more shale and coal-rich depositsin back-swamp areas. They form the upper part of theElleboog Formation which, as mentioned earlier,is the Dutch equivalent of the UK ScremerstonFormation. Similar to the preceding period, the well-

derived facies show a transition from proximalto distal towards the south (Cameron 1993; van Adri-chem Boogaert & Kouwe 1993–97). On seismicdata, this alternation of deposits produces a distincthigh-frequency, high-continuity seismic facies,which is continuous over the ESP. A change in seis-mic facies to lower frequencies and lower continuityoccurs across the major normal fault that bounds theplatform on its southern side; this is interpreted torepresent the transition to basinal conditions(Fig. 11). This change in seismic facies was mappedas a palaeogeographical boundary (Fig. 5c). Depositsfrom this interval show a gradual northwards changeto more proximal conditions, reflected in an increas-ing sand and coal content, and a decreasing carbon-ate and shale content.

Late Asbian–Pendleian: Yoredale Formation

Towards the end of the Asbian, a gradual relativesea-level rise occurred, as can be inferred from anupwards increase in the incidence and thickness ofcarbonate beds (Figs 7 & 8). This trend continuesinto the Brigantian. The Yoredale Formation con-sists of a cyclic alternation of carbonates and clastics,with rare coal seams (Fig. 4). It was deposited in aparalic setting and the cyclicity resulted from sea-level fluctuations. A typical Yoredale cycle startswith a sea-level rise establishing marine conditions,resulting in the deposition of carbonates and clays.Progradation subsequently results in a coarsening-upwards clastic succession that may end with acoal layer or palaeosol (Waters et al. 2007). Similarto the situation during the Asbian, the deposits aresandier in the north; the Brigantian in well E06-01

Fig. 11. Late Devonian–Early Carboniferous faultingon the southern flank of the Elbow Spit Platform. Theapproximate location is shown in Figure 1. DEF 3Dseismic data courtesy of Spectrum ASA.

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in the SE consists almost entirely of carbonate, inwell A16-01 of roughly equal amounts of carbonate,clay and sand, whilst well 39/07- 1 in the NE con-sists mostly of sand and clay with minor carbonatebeds (Figs 5b & 7). The youngest Yoredale depositsencountered in wells in the Dutch northern offshorethat have been dated with reasonable certainty areBrigantian in age. Deposits from the Pendleian,the earliest substage of the Namurian (Fig. 4), mayhave been drilled locally (for instance, in wellA16-01), meaning that Yoredale-type depositionpossibly continued into the early Namurian.

Namurian

At the start of the Namurian, the Visean bathymetryessentially still existed. It is commonly viewedthat extension had ceased, although indicationsexist that significant extension must still haveoccurred (Kombrink et al. 2008). During the Namur-ian, a turbidite-fronted delta system progradedsouthwards, the sediment source area was locatedtowards the north (Collinson 2005). South of thedelta, shales and turbidites were deposited. Whilstno penetrations of this interval exist in the northernDutch offshore (Fig. 4), their presence can be inferredfrom correlations to the UK onshore and well 43/17-2 (Fig. 2) (Collinson Jones Consulting 1995;Collinson 2005). The foresets of the progradingdelta were characterized by Millstone Grit and Kla-verbank deposition (Fig. 4). Since the system wasprograding, the formation boundaries are diachro-nous and expected to be older in the north than inthe south. This progradation continued during theWestphalian; Namurian Klaverbank deltaic deposits,for instance, closely resemble Westphalian A Kla-verbank deltaic deposits, but these facies werelocated further north during the Namurian. Similarto the rest of the Carboniferous, significant higher-order cyclicity occurred during this period. Once abasin (or part of a basin) had been filled, however,the basin never reverted back to fully basinal condi-tions (Collinson 2005).

Discussion

Reservoir potential

Visean. Two end-member models exist for predict-ing reservoir presence in the Visean: one modelpredicts reservoir presence based on fault control(Turner et al. 1993); the other focuses on the trans-gressive infill of palaeovalleys that incised during asea-level drop (Maynard & Dunay 1999). Both mod-els are probably valid end members.

The incised valley model is highly relevant, inparticular for the area close to the basin edge, as is

the case for the Breagh Field example. A predictionof reservoir presence here requires an understandingof the location of the valleys, which is challengingowing to their limited thickness and the limitedwell control. Somewhat surprisingly, the BreaghField is located in a zone with a relatively large pro-portion of shales (Fig. 5: well 42/13- 2).

The ESP (Fig. 2) was affected by episodic drown-ing and progradation, expressed in the cyclic alterna-tion of sandstones, shales, coals and carbonates. Thisis well documented for the Yoredale Formation, butthe results from this study show that this cyclicity isalso present in the underlying Elleboog Formation.The well data suggest that the proportion of clasticsin both formations increases northwards. North ofthe ESP, Late Devonian–Early Carboniferousfaulting led to the formation of the North ElbowBasin (Fig. 2) (ter Borgh et al. this volume, inpress). The basin trends WNW–ESE, measuresabout 60 km from SSE to NNW and can be contin-ued across the median line (Fig. 2) (Milton-Worssellet al. 2010; Arsenikos et al. 2018). More accommo-dation space was available in the basin during theVisean; the exact impact on reservoir potential isunclear and requires further study, but the overalltrend of an increasing clastic sediment contenttowards the north is supported by wells north ofthis basin.

The results from this study and the structuralframework developed for the study area (terBorgh et al. this volume, in press) demonstrate theactivity of syndepositional WNW–ESE-trendingfaults during the Late Devonian–Early Carbonifer-ous, with the southern boundary fault of the ESP asthemost prominent example. South of it, basinal con-ditions prevailed; north of it, paralic conditions. Con-sidering the significant offset at the fault and the rapidchange of seismic facies across it, mass-flow pro-cesses should be expected, and, although undrilled,reservoir-bearing turbidites may be present south ofthe fault (Fig. 11).

Namurian. The Namurian part of the KlaverbankFormation shows high net-to-gross deltaic sand-stones across the study area, in line with some ofthe most prospective reservoir intervals of the West-phalian (Figs 5&9). TheTulp andLeliefields (Fig. 1)confirm the reservoir potential of this interval.

Hydrocarbon charge from the Visean andNamurian

An important factor that has so far discouragedexploration in the northern Dutch offshore is the per-ceived absence of source rock outside the DCG. Asof yet, producing gas fields in this area are limitedto Mesozoic fields charged from the Early JurassicPosidonia Shale Formation, and Neogene shallow

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gas fields. Whether shallow gas originates fromthermogenic or biogenic sources is subject to debate,although a substantial biogenic contribution seemslikely (Schroot & Schüttenhelm 2003; van den Boo-gaard & Hoetz 2014).

There is a significant sampling bias of potentialsource-rock intervals towards samples from thepresent-day structural highs and towards samplesof coals. The bias towards the highs results fromthe fact that the wells have been primarily drilledhere. The bias to coals results from the often-madeassumption that all gas from the Carboniferous issourced from coals, meaning that sampling andobservations focused on these coals. Shales and dis-persed organic (plant) material may also have signif-icant potential (e.g. Besly 2016), however, but havehistorically been sampled less frequently. Coals arepresent not only in the Westphalian, but also withinthe Visean Elleboog Formation (the upper part ofwhich is the equivalent of the UK Scremerston For-mation), the Yoredale Formation and the NamurianKlaverbank Formation (Fig. 4).

The sampling bias towards samples from thepresent-day highs also affects maturity data – theavailable maturity data come mostly from the highs,and maturity in the lows should be expected to behigher. The source rocks in these lows are expectedto have reachedmaximumburial during theNeogene.The Lower Carboniferous on the present-day highs isalso expected to be at or close to maximum burial;Visean and Namurian deposits may have beenexhumed during the formation of the BPU by about1250 m (van Buggenum & den Hartog Jager 2007),but have since been buried again to depths greaterthan 1900 m. It is therefore encouraging that themea-surements from wells E02-01 and E06-01, taken onthe Elbow Spit High, are already in the late oil–early gas window. Wells A14-01 and A16-01 onlypenetrate part of the Namurian; this interval is inthe oil window and immature for gas. The Viseanhas not been penetrated in these wells. The only sam-ple representative for the present-day lows, fromwellB17-04, show that the Carboniferous has entered themain gas window here.

Well and seismic data show that it is likely thatsignificant amounts of Visean Scremerston coalsare present north of the ESP. This probably resultsfrom a facies shift; the wells in the E quadrantwere located close to the shoreline, where limitedamounts of coals have been preserved; wells 39/07- 1 and A-09-01 that contain significant amountsof coal are located in a more proximal setting(Fig. 5c). The trend of increasing coal contenttowards the north has been recognized previouslyin the UK offshore (Leeder 1988; Cameron 1993).The deposits are presently buried in the SG area todepths of up to at least 5500 m, with most of thedeposits at depths of between 3000 and 5000 m,

meaning that if coals are, indeed, present they aremost likely to be gas mature.

Organic material is dispersed throughout Viseanand Namurian units, and the source-rock potential ofthese deposits can be assessed using samples fromthe UK onshore, and from the offshore well 43/17-2, that drilled the Namurian in a basinal section. Theso-called marine bands within the basinal sequenceshow an average total organic content (TOC) of4.1 ± 0.78%, and the non-marine bands 1.89 ± 0.6%.Within the delta, these values are 3.86 ± 2.47 and1.6 ± 0.76%, respectively (Collinson Jones Consult-ing 1995). Similar deposits are to be expected in thesouthernmost part of the E and F quadrants.

Basin modelling in the German offshore directlynorth of the study area (Arfai & Lutz 2018) showsthat Visean–Namurian source rocks first becomemature in the Late Carboniferous, and that peak gen-eration and expulsion in the SG area occurs prior toLate Cretaceous inversion and continues to the pre-sent day. Visean–Namurian source rocks are inter-preted to have charged the A6-A gas field (Fig. 1,well A-06-01). In the Central Graben, generationoccurred until the Late Jurassic, at which point thesource rocks were buried to depths where theybecame overmature (Arfai & Lutz 2018).

Hydrocarbon charge from other source rocks

In the F quadrant and the eastern and southern partsof the E quadrant, Westphalian Coal Measures – thepredominant source rock in the Dutch onshore andoffshore – are mature present day. A lateral chargeof Westphalian gas into Visean and Namurian reser-voirs is possible on the southern flank of the ESP, asthe large-scale structure permits updip migrationfrom downthrown kitchens (Fig. 3).

Charge was confirmed in blocks E12 and E09, butthese discoveries were uneconomic as a result of thehigh nitrogen content of the gas (Table 3). Possiblesources of the nitrogen include very early mature orovermature organic sources and inorganic sources.In a regional evaluation, Verweij et al. (2017) pro-posed that, in the case of the E12 and E09 blocks,the nitrogen originated from coals and shales thatwere rapidly heated by magmatic intrusions. Intru-sions were identified in two of the three wells withhigh nitrogen contents (Table 3 & Fig. 9). Vitrinitereflectance data show that coals directly adjacent tothe intrusion are overmature (>5%Ro) (Philippeet al. 1992). Sills are often readily observed on seis-mic data in this area, allowing for an assessment ofthe economic risks associatedwith high nitrogen con-tents. The only other gas sample from a Paleozoic res-ervoir in the northern Dutch offshore showedacceptable nitrogen values (Table 3, A15-01: 16%).

Considering the significant normal faulting in theDCG and SG, lateral charge from stratigraphically

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younger units is possible. Within the DCG, theorganic-rich Jurassic Posidonia Shale Formationis preserved; indeed, a number of oil discoveries in

the DCG show that the formation is oil matureand locally gas mature. Basinal facies within theZechstein also have source-rock potential, and the

Fig. 12. Structures at the BPU level in the A quadrant, illustrating the types of structures that may form traps forhydrocarbons. The figure should not be regarded a detailed assessment of the prospectivity of the area as it is basedon a regional seismic interpretation and time–depth conversion, and only structures with a height greater than thecontour interval (62.5 m) are indicated. MSL, mean sea level; see Figure 1 for other abbreviations.

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Kupferschiefer at the base of the Zechstein may forman auxiliary source rock too. Although often over-looked, significant shows occur in Paleozoic andMesozoic units in a number of wells in the A quad-rant, providing proof that a mature source rock is pre-sent in this area as well. The number of wells thatdrilled into Paleozoic strata in this area is limited,but most of the wells that are available have signifi-cant shows; well A15-01 tested gas from tight Zech-stein carbonates and had oil shows in the Zechsteinand Triassic. Well A08-01 and A12-01 had gasshows throughout the Mesozoic and down to theZechstein, and well A12-02 had oil shows in theChalk Group.

Trap formation, top seal and fault seal

The structural geology of the study area is discussedin detail in ter Borgh et al. (this volume, in press).Based on that study, trap formation is discussed.An example of the relevance of the SG trend fortrap formation is shown in Figure 12; in the A quad-rant, the alternation of horsts and graben createspotential closures. The likely seal for such closureswould be provided by the Rotliegend Silverpit For-mation and the Zechstein salt, the latter of whichcan, in some cases, be observed to drape the horsts.The main risks for these traps is the presence of aneffective seal, as the Zechstein salt thins out towardsthe west, and the Silverpit Formation may, in fact,contain sandstone streaks locally. In the case thatthese are of sufficient reservoir quality they may bethe target, but otherwise they form a waste zone.Another reservoir and potential target that may bepresent below the Silverpit and Zechstein are theLower Rotliegend volcanics (de Bruin et al. 2015),although the flow capacity of this unit has not beendemonstrated.

Faults with a N040° trend are known to causecompartmentalization in the Cleaverbank High area(Oudmayer & de Jager 1993; van Hulten 2010),and it is not unlikely that they would have thesame effect in the study area. On the Cleaverbank

High, vertical offsets are generally in the order oftens of metres. This is also true for part of thestudy area, but large offsets (hundreds of metres to1 km) occur as well, with the Urania Graben locatedon the eastern flank of the ESP as the most prominentexample (ter Borgh et al. this volume, in press).Establishing under what conditions these faults actas a seal, and whether an increase in offset improvesor degrades the sealing and compartmentalizationpotential of the faults, could help to de-risk the seal-ing potential of this fault trend.

The N110° and N040° trends have the poten-tial for creating intra-Carboniferous closures; forinstance, in horsts or footwalls created by the N110°trend (Fig. 13). The hydrocarbon potential of thesestructures depends on the presence of either theSilverpit Formation or intra-Carboniferous seals asa top seal, combined with side seals along or acrossthe fault. The charge would have to be provided fromdownthrown Upper Carboniferous sources. Thecharge and sealing risks for these structures are con-siderable. This may be offset by their relatively largevolumes.

Strike-slip faults with a N070° trend wererecently identified on the ESP (ter Borgh et al. thisvolume, in press). As they have not been identifiedin public literature before, no studies are presentlyavailable to assess their sealing potential. Wherepop-up features are overlain by a seal, traps may bepresent.

Conclusions

Visean and Namurian deposits in the northern Dutchoffshore are found to offer a significant hydrocarbonpotential. The post-well analysis shows that out of the14 wells that encountered the Visean and Namurianin the northern Dutch offshore, only three canbe considered a valid test: two were positive and onenegative. The other wells were invalid tests of theplay because they did not test a valid structure. Thishas two main causes: first, all but two wells were

Fig. 13. Top Yoredale two-way travel time (TWT) map (in ms) illustrating structures at the Yoredale Formation levelin the E blocks. Mapping is on the 3D DEF survey, courtesy of Spectrum ASA.

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targeting a structure at another stratigraphic level,whereas no structure was present in the Visean orNamurian; and, secondly, often structures were map-ped using 2D seismic data only, whereas presentlyavailable 3D data show that no structure is presentat these well locations. Structures do exist, how-ever: in the Step Graben (SG) area Triassic–EarlyCretaceous extension caused structures to form,with closures in footwalls. Top and, in some cases,side seals would have to be provided primarily bythe Permian Silverpit and Zechstein Group deposits.Carboniferous–Early Permian extension causedstructures to form on the Elbow Spit Platform(ESP); traps at these levels would require intra-Carboniferous seals.

Core-plug data confirm that sandstones of Viseanand Namurian age with sufficient reservoir qualityare present across the area. Chances of encounteringreservoir rocks increase towards the north; theBreagh Field, although a commercial success, islocated on the southern edge of the area whereVisean–Namurian fluvial and shallow-marine reser-voir rocks are expected.

A number of potential source rocks have beenidentified: the presence of coal in nearby wells andthe palaeogeographical reconstruction suggest thatsignificant amounts of Visean Scremerston coalsmay have been preserved in the A and B quadrants.Additional coals were found in the Yoredale Forma-tion and the Namurian, and TOC measurementsshow that dispersed organic material is presentwithin the Visean and Namurian. In the southern Eand F quadrants, lateral charge may have come fromdownthrownWestphalian deposits, and from basinalVisean and Namurian shales that have not beendrilled but whose presence may be inferred fromthe palaeogeographical reconstruction. Additionalcharge may have come from downthrown basinalZechstein deposits and by long-distance migrationfrom the Lower Jurassic Posidonia Shale Formationin the Dutch Central Graben (DCG). Hydrocarbonshows that support this do occur. Hydrocarbon gen-eration and expulsion is expected to have occurrednorth, east and south of the ESP, and updip migrationonto the platform is considered possible.

Acknowledgements We thank reviewers AndreaJames and Malcolm Gall, and editor Alison Monaghan,for their constructive comments. Permission from SpectrumASA to show data from the DEF survey is muchappreciated.

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