Reservoir Quality Evolution of Upper Carboniferous (Westphalian) Tight Gas Sandstones, Lower Saxony Basin, Nw Germany

Abstract

This paper investigates reservoir quality development in tight Upper Carboniferous fluvial sandstones (Westphalian C/D) in the Lower Saxony Basin, NW Germany. The study integrates data from three outcrops (Piesberg, Woitzel and Hüggel) in the south of the basin with that from two wells (Wells A and B) located at gas fields approximately 50 km to the north. Petrographic and petrophysical data are related to the diagenetic evolution of the sandstones and the burial and structural history of the Lower Saxony Basin. The outcrop and subsurface data sets are compared in order to investigate the factors controlling reservoir quality evolution. Upper Carboniferous fluvial sandstones from the Woitzel and Hüggel outcrops and from Wells A and B have similar matrix permeabilities (0.01 to 10 mD), but matrix porosities vary between Well A (average 6%), Well B (average 10%), Woitzel (average 15%), and Hüggel (average 19%). Permeability reduction during burial is related to the formation of clay mineral cement, which was mainly controlled by variations in both the palaeo‐climate and in the sandstones’ depositional composition. Matrix porosity was controlled by local differences in burial history related to basin inversion tectonics. The greater amount of inversion‐related uplift at Well B (about 2.8 km) resulted in lower thermal exposure of the Westphalian sandstones at this location, which thus show higher matrix porosities than the sandstones at Well A which were uplifted by only about 1.2 km. Further increases in porosity in the outcrop sandstones may be related to the dissolution of carbonate cement during late‐stage uplift in near‐surface conditions. Upper Carboniferous fluvial sandstones from the Piesberg quarry show the poorest reservoir characteristics compared to the samples from the subsurface and the other outcrops, with matrix porosities averaging 6% and permeabilities <0.01 mD. Reservoir quality reduction was controlled by thermal anomalies associated with a large fault at the Piesberg quarry. By contrast, a few outliers in the sample data sets from Well B and the Piesberg quarry, which have permeabilities of more than 100 mD, show that faulting or natural fracturing may enhance reservoir quality within a particular area. Faults/fractures may act as potential migration pathways for leaching fluids, or may provide fracture‐permeability systems with production potential. Depositional setting, burial‐related diagenetic processes and structural characteristics in the Lower Saxony Basin need to be carefully evaluated in order to provide an improved understanding of the reservoir quality of the Upper Carboniferous sandstones.

Compaction control on diagenesis and reservoir quality development in red bed sandstones: a case study of Permian Rotliegend sandstones

“…13b) would result in an even better correlation coefficient of R = 0.91. Overall, clay minerals are interpreted to be one of the main controls on a deterioration of reservoir quality, as they might retain porosity in form of microporosity but contribute to a loss of effective porosity, resulting in reduced permeabilities, which is in line with the results of previous studies (Becker et al 2019;Ehrenberg 1990;Gaupp and Okkerman 2011).…”

“…Recent outcrop analog studies also demonstrated heterogeneity in lateral permeability in Triassic Buntsandstein of up to two orders of magnitude in a single bed several meters apart (Schmidt et al 2020b). Upper Carboniferous sandstones also show lateral permeability variations by two orders of magnitude over 150 m lateral distance in a 3 m bed (Becker et al 2019(Becker et al , 2017. However, it is commonly assumed to not vary significantly in the lateral direction in reservoir modelling approaches (Cannon 2018;Gibbons et al 1993).…”

“…Depositional systems are discussed to be one of the main or the main controlling factors on reservoir quality in literature (dos Anjos et al 2000;Griffiths et al 2019;Morad et al 2010). It is further developed towards an integrated approach of depositional systems overprinted by diagenesis during burial (Becker et al 2019;Busch et al 2020;Ehrenberg 1990;Gaupp and Okkerman 2011;Taylor et al 2010). This study comprises of fluvio-eolian sandstones only, consequently a population bias against a strong control depositional control due to the lack of depositional system variety is introduced into the data set.…”

“…Diagenesis affects the rock's porosity and permeability, and its viability as a reservoir (Morad et al 2010;Taylor et al 2010;Wadsworth et al 2016). Sandstones experience diagenetic alterations during burial; these are related to the initial detrital composition and grain coating minerals (Aagaard et al 2000;Busch et al 2020;Monsees et al 2020a), fluid type, -chemistry and -pressure (Bjørlykke and Høeg 1997;Gaupp et al 1993), thermal exposure over time (Becker et al 2019;Busch et al 2018;Lander et al 2008), and faults controlling temperature-overprint by hydrothermal fluid circulation (Farrell and Healy 2017;Farrell et al 2014;Wüstefeld et al 2017). Monsees et al (2020a) proposed grain-coatings to be a controlling factor on cementational and compactional behavior of Lower Permian Rotliegend sandstones natural gas reservoir in the North German Basin.…”

Coupling of diagenetic alterations and mechanical properties of Lower Permian siliciclastic sandstones: a pilot study

“…Reservoir sandstones also compact mechanically and chemically over geological timescales affecting petrophysical and mechanical properties (Houseknecht 1987;Lundegard 1992). Their reservoir properties change during subsidence, and their diagenesis is related to initial composition and grain coatings (Aagaard et al 2000;Busch et al 2020;Monsees et al 2020), fluid type, chemistry and pressure (Bjørlykke and Høeg 1997;Gaupp et al 1993), thermal exposure over time at depth intervals (Becker et al 2019;Busch et al 2018;Lander et al 2008), and faults controlling temperature overprint by hydrothermal fluid circulation (Wüstefeld et al 2017). It is thus of crucial importance for assessing the rock's porosity and permeability, and its viability as a reservoir (Morad et al 2010;Worden et al 2018).…”