Organic matter characterization of the Lower Cretaceous tight reservoirs in the Danish North Sea

Highlights

• Migration of oil into the Lower Cretaceous reservoirs charged from Upper Jurassic–lowermost Cretaceous Farsund Formation.

• Kerogen comcomprises immature marine algae, degraded bituminite and solid bitumen precipitated from the migrated late-oil, more abundant in the interbedded argillaceous Fischschiefer Member and Munk Marl Bed.

• The heterogeneous lithology, diagenetic bituminite and formation of secondary solid bitumen at various levels are important attributes needed while considering petrophysical calculations.

Abstract

This paper presents the first detailed organic geochemistry and petrography of the Lower Cretaceous tight reservoir units from the Valdemar Field, Danish Central Graben. The Tuxen and Sola formation chalks and the interbedded argillaceous Munk Marl Bed and Fischschiefer Member, respectively, contain thermally immature marine Type II kerogen, mainly algal liptinites, degraded bituminite and late-oil solid bitumen. The more clay-rich Fischschiefer Member and Munk Marl Bed constitute a relatively efficient seal for vertical migration and have significantly higher kerogen content as compared to the more calcareous Sola and Tuxen reservoirs. Evidence for significant oil migration can be observed across all the lithounits, highest in the Tuxen Fm which also constitute the main reservoir. Microscopic observations show a widespread distribution of granular degraded bituminite, formed by microbial degradation and diagenetic alteration of liptinites, and late-oil solid bitumen precipitated from the migrated oils. Biomarkers from rock extracts indicate open-marine depositional conditions of the source rocks that charged the hydrocarbons, having a geochemical composition similar to oils charged from the Upper Jurassic–lowermost Cretaceous Farsund Formation. The solid bitumen within such heterogeneous reservoir units might influence both reservoir quality and petrophysical properties.

Introduction

The Lower Cretaceous Tuxen and Sola formations are low porosity and permeability chalk reservoirs in the Valdemar Field of the Danish Central Graben (DCG), North Sea (Japsen et al., 2003; Jakobsen et al., 2004; Van Buchem et al., 2018). The Valdemar Field lies in the central part of the DCG and is dominated by the N-S elongated North Jens-Bo anticline, divided into two structural highs around the North Jens-1 well in the north and the Bo-1 well in the south (Jakobsen et al., 2005) (Fig. 1). It consists of separate Danian/Upper Cretaceous chalk and Lower Cretaceous chalk reservoirs and contains an estimated reserve of 5 million m³ oil and 2 billion Nm³ gas (Danish Energy Agency, 2018), however, the field has complex reservoir properties, tectonic evolution and charging history (Jakobsen et al., 2005; Van Buchem et al., 2018; Ponsaing et al., 2020a, Ponsaing et al., 2020b). The Tuxen and Sola reservoirs comprise pelagic/hemipelagic chalks and marly units, interbedded by thin argillaceous units of the Munk Marl Bed and Fischschiefer Member, respectively (Van Buchem et al., 2018). The chalk reservoirs are faulted and highly fractured with signs of overpressure and undercompaction (Jakobsen et al., 2005; Van Buchem et al., 2018; Ponsaing et al., 2020a, Ponsaing et al., 2020b). Production from the extremely low-permeable reservoir is based on natural depletion but is challenging. However, commercial production is achieved by long horizontal wells and creation of numerous sand-filled fractures (Danish Energy Agency, 2014).

The Upper Jurassic-lowermost Cretaceous marine shales of the Farsund Formation are the primary source rocks of the crude oil in the Valdemar Field. Bulk organic geochemical and organic petrological studies of the Farsund Formation have documented different organofacies and source rock quality of the shales which can be related to different oil family types in the DCG (Petersen et al., 2010, Petersen et al., 2013, Petersen et al., 2017; Ponsaing et al., 2020a, Ponsaing et al., 2020b). Different oil families in the Valdemar Field reveal a complex charging history from different organofacies and kitchen areas (Petersen et al., 2016; Schovsbo et al., 2018; Ponsaing et al., 2020a, Ponsaing et al., 2020b). Geochemical and petrographic studies on the Lower Cretaceous reservoirs rocks of the Valdemar Field are lacking, whilst such studies have provided valuable information about the reservoir quality, elsewhere (Jarvie et al., 2007; Passey et al., 2010; Sanei et al., 2015).

This study is the first investigation of the organic geochemical and the petrological properties from the Lower Cretaceous chalk reservoirs and argillaceous units in the North Jens-1 well of the Valdemar Field, DCG. Documentation of abundance and type of organic matter is important as both indigenous organic matter and secondary formed solid bitumen might play an important role in affecting reservoir quality and petrophysical interpretations. Organic matter is investigated from the calcareous Tuxen and Sola formations, and interbedded argillaceous Munk Marl Bed and the Fischschiefer Member, respectively. Geochemical parameters, such as total organic carbon (TOC, wt%), thermal maturity (T_max), oil content, kerogen type and lithology are studied using anhydrous pyrolysis geochemistry. The kerogen composition is studied by reflected white-light and fluorescence-inducing blue light organic petrography. Biomarkers from selected rock extracts are characterized to determine the source and genetic composition of the extractable petroleum fraction and compared with those from Ponsaing et al. (2020a).