High temperature quartz cementation and the timing of hydrocarbon accumulation in the Jurassic Norphlet sandstone, offshore Gulf of Mexico, USA

Abstract

Jurassic Norphlet Formation sandstone reservoirs in Mobile Bay (offshore Alabama, USA) produce gas from great depths (>6.4 km) and elevated temperatures (>200 °C). Quartz cement is concentrated at the top of these aeolian reservoirs forming a low porosity ‘tight-zone’ of widely variable thickness (3–58 m) above a more porous reservoir section. The extent of the tight-zone is independent of depositional facies and its thickness strongly influences well performance. Intergranular porosity in the Norphlet has been preserved by inhibition of quartz cementation due to the occurrence of robust grain-coating chlorite. Quantitative petrographic data reveal that chlorite grain-coat coverage is less in the tight-zone sands (mean = 92%) than in the reservoir sands (mean = 99%). Burial history and quartz precipitation kinetics modelling indicate that this seemingly minor difference in the completeness of grain coatings is sufficient to produce the observed differences in cementation and porosity. Quartz cementation to form the tight-zone took place under conditions of deep burial and high temperature. It followed in time the onset of pressure solution, emplacement of liquid hydrocarbons, and the precipitation of a solid hydrocarbon film (pyrobitumen) on the walls of the intergranular pores. Fluid inclusion microthermometry data indicate that volumetrically significant quartz cement precipitated at temperatures of 150 °C or greater from highly saline aqueous fluids. Hydrocarbon-bearing inclusions are notably absent in quartz cement of the tight-zone, implying that the pore fluids were predominantly brine during precipitation. Oil and gas associated with pyrobitumen evidently escaped from Norphlet traps prior to tight-zone cementation. Gas presently found in Norphlet reservoirs of Mobile Bay represents a relatively recent accumulation and is not the product of in situ thermal cracking of oil.

Petroleum reservoir quality prediction: overview and contrasting approaches from sandstone and carbonate communities

“…Pre-drill reservoir quality predictions may be made by accounting for the compositions, textures and burial histories of the prediction locations. This modelling approach reproduces wide ranges in observed extents of diagenetic alteration in sandstones (Walderhaug et al 2000;Taylor et al 2004;Perez & Boles 2005;Lander et al 2008a;Tobin et al 2010;English et al 2017) and has proven to be an accurate basis for pre-drill prediction of porosity, permeability, seismic velocities and other rock properties (Taylor et al 2010(Taylor et al , 2015Wojcik et al 2016;Chudi et al 2016). Current limitations of the approach include its applicability only to sandstones and siltstones, consideration of a restricted set of geochemical reactions and the lack of mass transfer simulation.…”

Enhanced porosity preservation by pore fluid overpressure and chlorite grain coatings in the Triassic Skagerrak, Central Graben, North Sea, UK

“…Reservoirs with anomalously high porosities are common in several hydrocarbon basins, e.g. Central Graben, North Sea, UK (Osborne & Swarbrick 1999;Nguyen et al 2013;Grant et al 2014); the Gulf of Mexico, USA (Taylor et al 2004;Ehrenberg et al 2008;; the Santos Basin, Brazil (Anjos et al 2003) and the Indus Basin, Pakistan (Berger et al 2009). Current understanding of porosity preservation in deeply buried sandstone reservoirs (.4000 mbsf, metres below sea floor) tends to be focused on how coatings of clay and microquartz on detrital grains can inhibit macroquartz cementation.…”

Clay Minerals from the Perspective of Oil and Gas Exploration

“…Some micropores are found in various clays regardless of whether the clay is authigenic or detrital in origin. Also, the existence of clay minerals does not always mean to reduce the reservoir quality, it may be good phenomenon to indicate good reservoir quality, e.g., coats of chlorite on sand grains can preserve reservoir quality because they prevent quartz cementation (Heald and Larese, 1974;Bloch et al, 2002;Taylor et al, 2004). Sometimes, the higher content zone of kaolinite is indicative of higher porosity.…”

“…The secondary porosity development and its relationship with clay minerals evolution has been investigated in many basins (Bloch et al, 2002;Taylor et al, 2004;Jiang et al, 2010). Let's use Liaodong Bay Sub-basin in Bohai Bay Basin in Northeast China as example again.…”