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The effect of interbedding on shale reservoir properties Kimmeridge Clay Formation

Figure 1. Structural elements of the North Sea showing the framework of the Viking Graben (modified from Dominguez, 2007) with inset of UK Quadrant 16 showing the location of wells studied (modified from DECC, 2013).

Highlights

  • Shale/sand interbeds of the Kimmeridge Clay Formation generate a ‘hybrid’ shale oil resource.
  • Rock-Eval S1 (kg oil/tonne rock) monitors shale retention and sand storage of oil.
  • About 50% shale/50% sand and low TOC provide optimum oil retention and storage.

Authors:

Munira Rajia, Darren R. Grockea, H. Chris Greenwella, Jon G. Gluyasa, Chris Cornfordb

aDepartment of Earth Sciences, Durham University, South Road, Durham, DH1 3LE, United Kingdom. bIntegrated Geochemical Interpretation Limited (IGI Ltd), Hallsannery, Bideford, Devon, EX39 5HE, United Kingdom

Accepted 20 April 2015

Abstract

North Sea oil is overwhelmingly generated in shales of the Upper Jurassic – basal Cretaceous Kimmeridge Clay Formation. Once generated, the oil is expelled and ultimately migrates to accumulate in sandstone or carbonate reservoirs. The source rock shales, however, still contain the portion of the oil that was not expelled. As a consequence such shales and juxtaposed non-source lithofacies can form the targets for the exploration of ‘unconventional oil’.

In this paper, we examine part of the Kimmeridge Clay Formation as a hybrid shale resource system within which ‘Hot Shale’ and organic-lean sandstone and siltstone intervals are intimately interbedded. This hybrid system can contain a greater volume of oil because of the increased storage capacity due to larger matrix porosities of the sand-silt interbeds, together with a lower adsorptive affinity in the interbedded sandstone. The relationship between the estimated volume percentages of sand and mudstone and free oil determined from Rock-Eval® S1 yields is used to place limits on the drainage of oil from source mudstone to reservoir sand at the decimeter scale.

These data are used to determine oil saturations in interbedded sand-mudstone sequences at peak oil maturity. Higher values of free hydrocarbon (as evidenced by the S1 value in mudstone) suggest that more oil is being retained in the mudstone, while higher S1 values in the interbedded sands suggest the oil is being drained to saturate the larger pore spaces. High silica content in the interbeds confirms the brittleness in this mudstone–sandstone lithofacies – an important factor to be considered for fracture stimulation to successfully work in a hybrid system. The key points of this hybrid unconventional system are the thickness, storage capacity and the possibility to capture a portion of the expelled, as well as retained oil.

Introduction

The Upper Jurassic–basal Cretaceous Kimmeridge Clay Formation of the North Sea is an active generating source rock for conventional oil and gas (Barnard and Cooper, 1981, Bernard et al., 1981, Goff, 1983, Cooper and Barnard, 1984, Cornford, 1984, Cornford, 1998), with further potential as an unconventional hydrocarbon reservoir. It may be something of a paradox that the Kimmeridge Clay Formation is neither Kimmeridgian (it is mainly Volgian–Ryazanian in age) nor is it a claystone, with silt-sized particles dominating as demonstrated below. A recent re-evaluation of the extensive Kimmeridge Clay Formation source rock and interbedded silicate-rich intervals have located potential for unconventional resource sweet-spots in terms of thickness, organic-richness, oil quality, maturity together with appropriate lithology, mineral content and natural fractures in the South Viking area of the North Sea (Cornford et al., 2014).

Figure 1. Structural elements of the North Sea showing the framework of the Viking Graben (modified from Dominguez, 2007) with inset of UK Quadrant 16 showing the location of wells studied (modified from DECC, 2013).

The present study focuses on 4 selected wells in UK Quadrant 16 in the southern part of the South Viking Graben of the North Sea (Fig. 1). The South Viking Graben is located within the United Kingdom (UK) and Norwegian sectors of the northern North Sea, and is bounded by the East Shetland Platform to the west and the Utsira High to the east. The 4 sampled wells lie in the UK sector of the Southern Viking Graben, with 3 of the wells (16/17-14, 16/17-18 and 16/17-19) drilled in the area where the Upper ‘Hot Shale’ Member is underlain by the fault-related clastic fans of the Brae Member of the Kimmeridge Clay Formation (Fig. 2). The fourth well (16/18-2) was drilled in a more axial position where the Hot Shales are underlain by more distal facies of the Brae Member fans.

Figure 2. Schematic cross section of the Southern Viking Graben showing the facies relationship between the Upper and Lower Hot Shale and Brae members of the Kimmeridge Clay Formation.

Figure 2. Schematic cross section of the Southern Viking Graben showing the facies relationship between the Upper and Lower Hot Shale and Brae members of the Kimmeridge Clay Formation.

The formation of the Viking Graben was initiated during the Permo-Triassic from different phases of extension followed by regional subsidence (Glennie, 1986, Erratt et al., 2010). During the Middle Jurassic a domal uplift in the central area of the North Sea Basins arguably initiated the development of the Central and Viking grabens. In the Late Jurassic–Early Cretaceous, block faulting and tilting created the grabens, together with some strike-slip movements offsetting the graben margin faults. These offset zones played a key role in focussing coarse clastics into the deep water of the grabens, which forms the submarine fans of the Brae Member in UK Quadrant 16 (Stow, 1983, Turner et al., 1987).

Separation of the Viking Graben into northern and southern sectors occurred during structural development in the Jurassic (Richards et al., 1993). In the Middle Jurassic (Callovian–Oxfordian), structural extension produced continuous rapid subsidence in these grabens. These processes combined to produce a relatively isolated deep water basin which became relatively sediment-starved in the Upper Jurassic. With a distal connection to the Boreal seaway far to the north and in the absence of water circulation, the deep restricted basins accumulated marine Kimmeridge Clay sediments rich in organic matter (Cornford and Brooks, 1989, Gautier, 2005).

Rapid subsidence and burial favours the maturation of the accumulated source rocks with oil generation beginning in the Cretaceous with peak generation during the Tertiary. During the Upper Jurassic to Early Cretaceous (Kimmeridgian to Ryazanian), the active western graben margin fault shed coarse clastics to form Brae Formation conglomerates and sands into the deep water trough of the south Viking Graben (Partington et al., 1993). The pebbly to fine sandstones of the Brae Formation are interpreted as proximal deep-water slope apron fans derived from the East Shetland Platform and Fladen Ground Spur (Underhill, 1998, Justwan et al., 2005, Stow, 1983). The organic-rich mudstone and interbedded fan sands, together with distal and inter-fan areas, form the basis of a sweet spot for a hybrid unconventional petroleum system (Fig. 2).

Though deep water persisted, bottom water oxygenation returned in the Early Cretaceous as the graben became a connection between the Boreal and Tethys oceans (Cornford and Brookes, 1989). By the Late Cretaceous, rifting in the North Sea region essentially ceased, with regional thermal subsidence most prominent near the axis of the abandoned rift resulting in basin depocenters for syn- and post-rift sediments (Cornford and Brooks, 1989, Ziegler, 1990, Cooper et al., 1995, Faerseth, 1996, Gautier, 2005, Johnson et al., 2005, Erratt et al., 2010).

The Kimmeridge Clay Formation is a mature source rock for both oil and gas in the graben centre. This interpretation is based on measured maturity parameters such as vitrinite reflectance and Rock-Eval Tmax (Cornford et al., 2014), thermal modelling (Schlakker et al., 2012), direct measurement of oil generation within the source rock from solvent extraction and Rock-Eval S1 yields (Schaefer et al., 1990) and oil/source rock correlations based on molecular maturity parameters (Cornford et al., 1983). Burial history modelling, calibrated against measured parameters, suggest a burial depth deeper than 3200 m below sea bed for maturity and generation from the typical Type II oil-prone kerogen (Cornford, 1998).

As well as oil generation, deep burial of the mudstones leads to loss of porosity (mainly by compaction) and permeability (assisted by diagenetic cementation). Inter-granular pore systems within interbedded sandstone from Miller and Kingfisher Fields in UK Quadrant 16 average up to about 10 vol. % (Gluyas et al., 2000, Marchand et al., 2002, Spence and Kreutz, 2003). The porosity of the mudstones is less well constrained, however, Cornford et al. (2014) reported bulk volumes in the range of 5%.

Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo. In an independent way he’s researching about shale gas & tight oil and building this website to spread the scientist knowledge of the shale industry.
http://www.allaboutshale.com

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