The Role of Secondary Porosity in the Course of Sandstone Diagenesis

The role played by carbonate cementation in controlling reservoir quality of the Triassic Skagerrak Formation, Norway

“…Whereas, the data with higher δ 13 C values (about 1.5‰, VPDB; Fig. 12) probably indicate carbon derivation within microbial methanogenesis zone, bacterial fermentation and contribution from atmospheric CO 2 (Irwin and Hurst, 1983;Morad et al, 1998 (Bjørlykke, 2014;Burley and Kantorowicz, 1986;Giles, 1987;Schmidt, 1979;Taylor et al, 2010). Perhaps more importantly is whether there are sufficient organic acid to dissolve the carbonate cements or significant fluid flow with undersaturated solutions to replenish the system (e.g.…”

“…Three criteria for identification of secondary porosity after the dissolution of carbonate cements in sandstones have been proposed by Schmidt (1979). These criteria include the occurrence of oversized pores due to the dissolution of grain-replacive carbonate cements, partially dissolved carbonate cements with etched outlines, and grain-replacive carbonates surrounded by open pores.…”

“…(Taylor et al, 2010). The undersaturated pore water may be derived from formation water with carboxylic acid sourced from organic matter, meteoric water with CO 2 , compactional pore water with organic CO 2 , cooled deep formation water, and reactions of clay minerals (Bjørlykke, 1984;Giles and Boer, 1989;Schmidt, 1979;Surdam et al, 1984;Taylor et al, 2010). The Skagerrak Formation experienced shallow burial over a long period of time (Fig.…”

“…during deeper burial, organic CO 2 and carboxylic acid are sourced from the organic matters and migrate into adjacent sandstones to dissolve carbonate cements (Schmidt, 1979;Surdam et al, 1984). However, no apparent faults or fractures are observed in Skagerrak Formation, and thus carbonate cements are unlikely dissolved by cooled deep formation water (Giles and Boer, 1989 Figure 12 Carbon and Oxygen isotope data for calcite cement.…”

Reservoir description and characterization of Eni field Offshore Niger Delta, southern Nigeria

“…Accurate porosity information is required for characterizing a reservoir, especially due to its role in evaluating the volume of hydrocarbon stored in the pore spaces located within sand grains (Schmidt and McDonald 1980). Porosity distribution value across the reservoir sand H10 ranges from 0.25 to 0.32, while the value ranges from 0.28 to 0.32 and 0.29 to 0.34 in G20 and E40 sands, respectively (Figs.…”