Sandstone porosity

The sandstone porosity in thin sections oscillates from below 1 to 22.3 vol. % of rock (average 8 % vol.) Primary porosity dominates over secondary porosity in the sandstones. 

Fiichtbauer H. (1967) Influence of different types of diagenesis on sandstone porosity. 7th World Petrol. Cong., 353-369. 

Lundegard P. D. (1992) Sandstone porosity loss—a big picture view of the importance of compaction. J. Sedim. Petrol. 62, 250-260. 

Sandstone porosity loss versus depth in Haltenbanken is similar to trends seen for the North Sea, especially between 1.4 and 2.6 km (Bjorlykke et al. 1989). This could suggest that overpressure does not influence the porosity depth trends in these basins. It is possible, accordingly, that the lack of correlation between overpressure and shale porosity reported at Haltenbanken by Hermanrud et al. (1998) is a manifestation of disequilibrium in the sense that the shales did not have time to respond chemically to the overpressure development. This suggests that mechanical models for compaction cannot adequately explain porosity loss in deep shales and that a time/temperature... 

A study of pressure solution undertaken to show which mechanism really controls the porosity has three aims (1) to evaluate quantitatively the spatial distribution of pressure solution and quartz cementation on a regional scale in the sandstones, (2) to evaluate the influence of certain geological variables like median grain size, composition of clay binders, temperature, etc. on pressure solution and (3) to evaluate its role in quartz cementation during evolution of the sandstone porosity. 

The pores between the rock components, e.g. the sand grains in a sandstone reservoir, will initially be filled with the pore water. The migrating hydrocarbons will displace the water and thus gradually fill the reservoir. For a reservoir to be effective, the pores need to be in communication to allow migration, and also need to allow flow towards the borehole once a well is drilled into the structure. The pore space is referred to as porosity in oil field terms. Permeability measures the ability of a rock to allow fluid flow through its pore system. A reservoir rock which has some porosity but too low a permeability to allow fluid flow is termed tight . 

Carbonate rocks are more frequently fractured than sandstones. In many cases open fractures in carbonate reservoirs provide high porosity / high permeability path ways for hydrocarbon production. The fractures will be continuously re-charged from the tight (low permeable) rock matrix. During field development, wells need to be planned to intersect as many natural fractures as possible, e.g. by drilling horizontal wells. 

Tar Sands. Tar sands (qv) are considered to be sedimentary rocks having natural porosity where the pore volume is occupied by viscous, petroleum-like hydrocarbons. The terms oil sands, rock asphalts, asphaltic sandstones, and malthas or malthites have all been appHed to the same resource. The hydrocarbon component of tar sands is properly termed bitumen. 

A and B are functions of many parameters such as non-shale-rock strength, volume of shale, shale rock strength, effective porosity, and overpressured shale rock strength. These parameters are first initialized with local knowledge, for example, the volume of shale, of 65% sandstone FORS, etc. The calculated... 

Figure 3. Porosity measurements on a microscopic scale for a small (2 cm X 2 cm X 30 urn) thin section of sandstone impregnated with fluorophor-doped polymer. Average porosity - 16.3% range of porosities - 1.8-42%.

Fig. 1.14 Propagators for water flowing with an average interstitial velocity of 610 pm s-1 through a sample of sandstone of 15.3% porosity. The curves in both plots refer to encoding times of A = 50, 85, 140, 220, 330, 500, 750, 1100 and 1650 ms. Left propagators in the z direction (along the flow axis) the disappearance of a pronounced peak near zero...

Fig. 3.6.4 Comparison of 2-MHz NMR porosity with buoyancy porosity for 192 sandstones [18].

Fig. 3.7.4 (A) CRMI results of pressure versus volume on the Berea sandstone sample with a porosity of 20% and permeability 0.2 darcy. The two lines are raw CRMI data and the corrected data by a calibration run. Transducer noise was also filtered. The amount of the correction is fairly small and the two data sets overlap. (B) CRMI pore body volume distribution showing a predominant peak at around 20 nL. Figure from Ref. [57] with permis-...

Filter. A filter is used in some cases when coagulation and sedimentation do not completely separate the solids from the liquid waste in areas where sand and sandstone formations are susceptible to plugging. Filters with a series of metal screens coated with diatomaceous earth or cartridge filters are typically used.27 Where limestone formations with high solution porosity are used for injection, filtration is usually not required. 

Procedure. Core floods were carried out in horizontally mounted Berea sandstone cores of length 61 cm and diameter 5 cm. Porosity varied from 18 to 25% and brine permeability from 100 to 800 Jim2. The cores were coated with a thin layer of epoxy and cast in stainless steel core holders using molten Cerrobend alloy (melting point 70°C). The ends of the cores were machined flush with the core holder and flanges were bolted on. Pore volume was determined by vacuum followed by imbibition of brine. Absolute permeability and porosity were determined. The cores were initially saturated with brine (2% NaCl). An oil flood was then started at a rate of lOm/day until an irreducible water saturation (26-38%) was established. 

Holcomb, D.L. "Low Concentration Hydrochloric-Hydrofluoric Acid Mixtures for Stimulation in Low Porosity, Low Permeability Sandstone Formations," Proc. Svmp. Stimul, Low Permeability Reservoirs.1976. 72-86, Colo. Sch. Mines, Golden. 

Baccar, M. B. and B. Fritz, 1993, Geochemical modelling of sandstone diagenesis and its consequences on the evolution of porosity. Applied Geochemistry 8, 285-295. 

Properties and extraction processes Tight-formation gas is natural gas trapped in low-porosity (7 to 12%), low-permeability reservoirs with an average in-situ permeability of less than 0.1 millidarcy (mD), regardless of the type of the reservoir rock tight gas usually comprises gas from tight sands (i.e., from sandstone or limestone reservoirs) and shale gas. Sometimes tight gas also comprises natural gas from coal and deep gas from reservoirs below 4500 m. Shale gas is produced from reservoirs predominantly composed of shale rather than from more conventional sandstone or limestone reservoirs a particularity of shale gas is that gas shales are often... 

FIGURE 3.3 Reduction in porosity in sandstone as a result of cementation and growth of authigenic minerals in the pores which affects the amount, size, and arrangement of the pores. (Modified after Ebanks, 1987.)... 

Schmidt, V., McDonald, D. A., and Platt, R. L., 1977, Pore Geometry and Reservoir Aspects of Secondary Porosity in Sandstones Bulletin of the Canadian Petroleum Geology, Vol. 25, pp. 271-290. 

Carbonate rocks consist mostly of calcite and dolomite with minor amounts of clay. The porosity of carbonate rocks ranges from 20 to 50%, but in contrast to sandstone, it tends to decrease with depth. Often, carbonate rocks are fractured, providing a permeability that is much greater than the primary one. In some cases, initial small-scale fractures in calcite and dolomite are enlarged by dissolution during groundwater flow, leading to an increase in rock permeability with time. 

Karathanasis AD, Johnson DMC, Matocha CJ (2005) Biosolid colloid mediated transport of copper zinc and lead in waste-amended soils. J Environ Qual 34 1153-1164 Kieffer B, Jove CF, Oelkers EK, Schott J (1999) An experimental study of the reactive surface area of the Fontainebleau sandstone as a function of porosity, permeability, and fluid flow rate. Geochim Cosmochim Acta 63 3525-3534... 

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