Unconventional oil and gas is defined as oil and gas exploitable by directly drilling and fracturing of low permeability fine grained rocks acting as both source and reservoir (Jarvie et al., 2007, Abrams et al., 2014). For both unconventional oil and unconventional gas, the fine-grained rocks should be sufficiently thick and contain mid to late mature organic matter. Decomposition of organic-rich kerogen (and probably the related bitumen) yields liquid and gas, as well as potential for organic-hosted porosity as shown by numerous Scanning Electron Microscope (SEM) images (Loucks et al., 2009, Bernard et al., 2013). Reservoir properties for unconventional resource assessment include; lithology, thickness, organic matter-richness, kerogen types, thermal maturation, burial/uplift history, timing, mineralogy, fracture networks, fluid properties (density, viscosity, water saturation, phase behaviour) and expulsion efficiency (Jarvie et al., 2007, 2013; Abrams et al., 2014).
Optimum combinations of these properties can be used to predict and identify sweet spots, though the controlling processes seem to vary from basin to basin. There is limited compensation within these properties, for example, a lack of maturity cannot be compensated by a greater thickness. However, whether oil or gas is produced from unconventional resources is largely a function of the source rock maturity rather than kerogen type (Jarvie et al., 2007).
Shale oil resources are defined as a source rock (organic-rich mudstones with juxtaposed organic-lean sandstone, silt) that has generated, expelled and retained oil at mostly lower thermal maturity: hence, lower temperature and pressure conditions than shale gas. The retained oil is either stored in the mudstone itself or is expelled into interbedded thin non-source facies. The term “hybrid system” is used to describe this type of organic-rich mudstone with juxtaposed (interbedded, underlying and/or overlying) organic-lean non-source lithofacies (Jarvie, 2012, Cornford et al., 2014). The organic-lean non-source lithofacies has less affinity for oil so it produces more readily leading to higher recovery of the original oil in place (OOIP). In contrast, organic-rich mudstone tends to retain more oil due to sorptive affinity and lower permeability (Jarvie, 2012).
At this early stage of the exploitation cycle, there are no reliable indicators for identifying commercial shale oil productivity in the UK, with the potential and resource estimates being largely based on the criteria obtained from shale oil production in the North America. Examples of hybrid systems in North America, both organic-rich, low permeability intervals and interbedded, organic-lean intervals are presently being explored in Late Devonian–early Carboniferous Bakken Formation, the Late Cretaceous Niobrara Formation (Jarvie et al., 2007, Jarvie, 2012), and arguably the Triassic Montney Formation of British Columbia (Chalmers et al., 2012, Chalmers and Bustin, 2012).
North Sea Kimmeridge Clay Formation
The Upper Jurassic Kimmeridge Clay Formation is the main source rock for the North Sea oil and gas fields in the Central and Viking Grabens. The dark, olive-grey calcareous to non-calcareous organic-rich mudstones in the Viking Graben area range in age from Volgian to Ryazanian. These sediments were deposited in a restricted marine embayment of the Boreal seaway in the north, resulting from crustal stretching and formation of the three main North Sea grabens (Cornford and Brooks, 1989, Cooper et al., 1995, Erratt et al., 2010).
Sediment accumulation followed the widespread subsidence that occurred during the Late Jurassic to Early Cretaceous rifting episodes. Concomitant global sea-level rise led to the Late Jurassic marine transgression event, resulting in the Oxfordian Heather Formation, comprising of organic-lean mudstones deposited under oxic bottom water conditions. With the closing of the Boral-Tethyan connection, high sedimentation rates, elevated organic matter productivity (probably controlled by nutrient supply) and increased water depths all promoted stratified anoxic bottom waters. With greatly improved organic matter preservation, this resulted in the deposition of the thick, organic-rich Kimmeridge Clay Formation (Cornford and Brooks, 1989, Tyson, 2004).
During the Upper Jurassic, conglomerates and sands were periodically transported as submarine fans by gravity flow across the uplifted graben edge of the Shetland Platform and in to the main graben (Partington et al., 1993). These sands were fed into the basin via graben-edge ‘notches’ formed over ramps/transfer zones (transform fault lineations) which breached the uplifted footwall. These coarse clastics sediments, called the Brae Formation were deposited into the anoxic basin of the main South Viking Graben, where they are found interbedded with the mudstones of the Kimmeridge Clay Formation (Leythaeuser et al., 1984, Leythaeuser et al., 1987, Turner et al., 1987). This sediment association (Fig. 2) forms the target for the present study.
The Kimmeridge Clay Formation can be assessed as a potential shale oil reservoir since it contains actively generating source rocks and significant quantities of residual oil in the fully mature areas of the North Sea (Cornford et al., 2014). A maximum thickness of 1,100 m is recorded for the Kimmeridge Clay Formation in the South Viking Graben (Gautier, 2005), with the maturity and lithofacies of these source rocks varying laterally and vertically across the study area (Fig. 3).
Figure 3. Identification of optimum facies (lateral), and maturity (vertical) for extracting unconventional liquids from the Kimmeridge Clay Formation of the South Viking Graben, North Sea.
This illustration emphasises the need to overlap aspects of thermal maturity (upper) and of organo-facies (lower) to identify optimal ‘sweet spots’ for drilling unconventional wells. The interaction of facies and maturity are optimized where total organic content (TOC) values are high and the kerogen type is oil-prone. Where oil saturation is high, asphaltene contents are extremely low and resins are reduced, and the interval lies in the volatile oil window where API gravities are generally >40°API and gas/oil ratios (GORs) are in the range of 1000–15,000 scf/stb (standard cubic feet of gas/barrel of oil) (Jarvie, 2012).
In the South Viking Graben, the formation generally thickens towards the basin margin fault and thins over the crest of the intra-basinal fault blocks (Richards et al., 1993). The thickening into faults is less prominent for the Upper and Lower Hot Shale mudstones, than for the pebbly to fine sands of the Brae Formation (Fig. 2). Three gross facies are recognized: Kimmeridge Clay Hot Shale (both Upper and Lower), an intermediate facies of interbedded sands and mudstones termed the Tiger Stripe facies, and massive sand and conglomerates of the Brae Formation (Fig. 2). The Tiger Stripe facies is mainly found below the Upper “Hot Shale” and above the main Brae Formation, and comprises an alternating mudstone and fine-grained sand interbeds.
It is interpreted to have been deposited by low-density turbidity currents on the outer submarine fan, inter-fan and in the basin plain environments (Reitsema, 1983, Stow, 1983, Leythaeuser et al., 1984, Turner et al., 1987, Roberts, 1991, Rooksby, 1991). Lithological and compositional heterogeneity of the mudstone–sandstone interbeds is caused in part by variation in organic richness (TOC) and kerogen type as evidenced by the core samples in the study area (Huc et al., 1985, Isaksen and Ledje, 2001).
Methods: sampling and analytical procedures
In this paper, eighteen core plugs from four south Viking Graben wells (16/17-14, 16/17-18, 16/17-19, 16/18-2) drilled between 1984 and 1991 were sampled from the British Geological Survey core storage in Keyworth, Nottingham UK (Fig. 4, right). The samples were selected based on the visual inspection of slabbed cores and estimates of percentage of mudstone and sandstones at different intervals from each well (Fig. 4, right). The first three wells lie on the western margin of the graben along the Tiffany-Toni-Thelma field trend, and the latter (16/18-2) is in the trough axis to the east near the UK-Norwegian boundary (Figs. 1 and 2).
Figure 4. Left: Thin-section photomicrographs of sand-dominated mudstone interbeds: (4A) Sandstone-dominated photomicrograph thin section images from 4127.4 m (well 17/18-2); (4B) Sandstone alternating with organic-rich mudstone layers, impregnated with blue-dyed resin showing breakage at the contact boundary between sandy and muddy layer (probably core disintegration during drilling and sampling); (4C) Organic-rich 70/30 sandstone/mudstone from 3552 m (well 16/17-19); (4D) 50/50 sandstone/mudstone with desiccation fractures from 4126.2 m (well, 16/18-2); (4E) organic-rich sandstone–mudstone from 3, 582.9 m (well 16/17-19). Right: Example core photograph showing regions that were sampled based on a visual estimate of the percentage of sand and mud.
In terms of depth (metres sub-Kelly Bushing), the cores from the 16/17-19 well are the shallowest (3552-82 m) followed by those from 16/17-18 at 3720-83 m. The cores from the other two wells are substantially deeper with the 16/18-2 having a short cored interval of 4126.5–28.7 m and 16/17-14 at 4193.7-4211.9 m (Table 1, appendix). Since they represent the upper part of the sequence (Upper Hot Shale and Tiger Stripe), the units sampled are taken to be Volgian to Ryazanian in age, and consists of mudstone sequences with interbedded sandstone (Fig. 2). The percentage of the mudstone and sandstone were visually estimated from full cores and core plugs initially, with the estimates being substantiated by observing thin sections under an optical microscope.
Table 1. TOC and Rock-Eval Pyrolysis data for 18 core plug samples from the Kimmeridge Clay Formation of the South Viking Graben, North Sea, UK.
The composition of the sandstone–mudstone mineralogy and porosity distribution were derived from petrographic thin sections, X-ray diffraction (XRD) and visual core descriptions. Geochemical analyses were carried out to determine the source rock potential, kerogen-type, maturity, carbon-isotope composition and retained hydrocarbon yield.
Eighteen petrographic thin-sections were analysed for mineralogy, rock fabric, texture, fractures and fossil contents. Thin sections were polished to approximately 20 μm in thickness. In terms of simple lithofacies, the abundance of sand in the mudstone was estimated from the thin sections, with each sample being placed in one of five categories (Fig. 4, right).
X-ray diffraction (XRD)
A Bruker D8 Advanced diffractometer set to Bragg-Brentano geometry reflection mode analysis was used to record the X-ray diffraction pattern of 17 powdered samples. The samples were prepared and mounted on a dry slide glass and held in a sample holder. The X-ray radiation was Cu Kα (1.54056 nm) and the sample was scanned between 5 and 65° 2θ angle with a 0.02° 2θ step size (Moore and Reynolds, 1997).
Total organic carbon and pyrolysis analysis
Thermal vaporization and pyrolysis analysis of powdered samples was carried out using a Rock-Eval 6 Instrument to obtain information on hydrocarbon generation, potential, type and maturity of organic matter in the samples. Norwegian Petroleum Directorate (NPD) rock standard, and Jet-Rock 1 (JR-1) standards were analysed every tenth sample and checked against the acceptable range given in NIGOGA standard documentation (Espitalié et al., 1985a; Peters, 1986, Lafargue et al., 1998, Weiss et al., 2000). The TOC (total organic carbon) content of the samples was measured on a Leco SC-632 instrument as weight percent of the initial rock sample. Prior to TOC analysis samples were treated with dilute hydrochloric acid to remove any carbonate.
Sample preparation for stable isotope analysis
Each sample was ground into fine powder using a Retsch RM100 mill. The powdered samples were placed in 50 ml centrifuge tubes, and 40 ml of 3 M HCl were poured onto the samples for decalcification and left to stand overnight. Only four samples (from 3572.0 m in well 16/17-19, and 3782.9 m in well 16/17-18 and from 4211.7 m to 4193.6 m in well 16/17-14) showed visible moderate to violent reaction to HCl, indicating high carbonate content. All the samples were rinsed five times with de-ionised water to remove any residual HCl. The samples were then dried for 24 h at 50–60 °C, and then ground again using an agate mortar and pestle. Each sample was then accurately weighed into tin capsules for stable isotope analysis.
Stable isotope measurements were performed at Durham University using a Costech Elemental Analyser (ECS 4010) coupled to a ThermoFinnigan Delta V Advantage. Carbon-isotope ratios are corrected for 17O contribution and reported in standard delta (δ) notation in per mil (‰) relative to the Vienna Pee Dee Belemnite (VPDB) scale. Data accuracy is monitored through routine analysis of in-house standards, which are stringently calibrated against international standards (e.g., USGS 40, USGS 24 and IAEA 600). Analytical uncertainty for δ13Corg measurements is typically ±0.1‰ for replicate analyses of the international standards and typically <0.2‰ on replicate sample analysis. In addition to the Leco analysis mentioned above, total organic carbon was obtained as part of the isotopic analysis using an internal standard (i.e., glutamic acid, 40.82% C).
Results and discussions
Mudstone and sandstone mineralogy
Observations from 18 thin-sections suggest that, generally, the interbedded sandstones are fine-medium grained sands, with silty high organic carbon contents in the mixed sandstone/mudstones and lower organic carbon content in the purer sandstone facies (Fig. 4A–E)
The mudstone-dominated lithologies are black to dark grey, silty, partly laminated with gradational boundaries between the mudstones and the interbedded light-grey sandstones (Fig. 5A, B and D). At this magnification it is clear that even the mudstone-rich samples contain mainly silt (2–63 μm), with little to no clay-sized fraction (<2 μm) apparent.
Figure 5. Thin-section photomicrographs of hybrid shale system displaying various mudstone–sandstone interbeds: (5A) 30/70 sandstone/mudstone fine-medium sandstone, dark-grey, sub-angular-sub-rounded, moderately sorted from 3564.1 m (well 16/17-19); (5B) 50/50 sandstone/mudstone with darker organic-rich layers from 3780.4 m (well 16/17-18); (5C) Sandstone dominated sample with visible shell fragments and woody (Type II kerogen) remnants from 4193.6 m (well 16/17-14); (5D) mudstone-dominated samples from 4194.7 m (well 16/17-14), the light-grey colour within the mudstone are thin siliceous sandstone layers, some only a grain thick.
X-ray diffraction (XRD) results suggest these samples are dominated by quartz, clay, organic matter and pyrite (Fig. 6). Kaolinite, illite/smectite and some chlorite are the dominant clay minerals identified in all samples. In general, a more intense XRD peak for quartz is observed in the sandstone dominated samples, though fine quartz is also a significant fraction of the mudstones. Brittleness measures the amount of stored energy within the grains prior to failure, which is controlled by the temperature, effective stress from burial, diagenesis texture, total organic carbon content and fluid type. The abundance and preservation of silicate minerals (Fig. 6) in the sand-rich samples suggest little diagenetic alteration, as expected given the limited depth range, with the primary quartz content likely to exert control on the brittleness of the interbedded sandstone and mudstone.