Porosity reservoir rock

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 . 

In nearly all oil or gas reservoirs there are layers which do not contain, or will not produce reservoir fluids. These layers may have no porosity or limited permeability and are generally defined as non reservoir intervals. The thickness of productive (net) reservoir rock within the total (gross) reservoir thickness is termed the net-to-gross or N/G ratio. 

Reservoir simulation is a technique in which a computer-based mathematical representation of the reservoir is constructed and then used to predict its dynamic behaviour. The reservoir is gridded up into a number of grid blocks. The reservoir rock properties (porosity, saturation, and permeability), and the fluid properties (viscosity and the PVT properties) are specified for each grid block. 

Once the potential for hydrocarbons has been verified in a region, explorationists look for reservoir rocks that potentially contain the hydrocarbons. Reservoir rocks are typically comprised of sands or carbonates that have space, called porosity, tor... 

The porosity of a reservoir rock is the ratio of the pore volume to the total volume of the rock and is expressed either as a percentage or as a fraction. 

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... 

An important property of high-T systems is the reservoir formation porosity and the mass fractions of water and steam occupying the pores. These mass fractions and the formation porosity determine how large a fraction of the heat of the system is stored in the fluid and how large a fraction in the rock. Usually the quantity of heat stored in the reservoir rock is considerably larger than that stored in the fluid. This is particularly the case for vapour-dominated systems. For a liquid-dominated system at 250 °C with 10% porosity and no steam, the quantity of heat stored in the fluid in 1 m3 of reservoir rock is about 87 MJ, but that stored in the rock is some 500 MJ. The corresponding number for the heat stored in steam in a vapour-dominated system is only 5.6 MJ. 

From the above discussion, it is seen that the long-term performance of a geothermal reservoir depends on reservoir rock porosity, recharge, and... 

A method for determining the effective porosity of a reservoir-rock. Penn. State College Min. Ind. Exper. Sta. Bull. No. 10. 

A. J. Lucas, G. K. Pierens, M. Peyron, T. A. Carpenter, L. D. Hall, R. C. Stewart, D. W. Phelps, and G. F. Potter, Quantitative porosity mapping of reservoir rock cores by physically slice selected NMR, in P. F. Worthington and C. Chardaire-Riviere, (Eds.), Advances in Core Evaluation III Reservoir Management, Reviewed Proceedings of the Society of Core Analysts Third European Core Analysis Symposium, France, September 14—16, 1992, Gordon and Breach Science Publishers, Reading, UK, 1993, pp. 3-24. 

The rocks in which large volumes of petroleum are able to accumulate are termed reservoir rocks. They require suitable porosity (typically 10-25%) and permeability (typically 1-1000mD 1 mD or milliDarcy = c.10 9m2), with reasonably sized pores and an impermeable cap rock or seal to prevent escape of petroleum over geological time periods. They must also be in place before the onset of oil generation. Sandstones often provide suitable reservoir characteristics. More than 60% of all oil occurrences are in clastic rocks, while carbonate reservoirs account for c.30%. The smaller molecules present in gases can escape through narrower pores than oil components, and seals are often slightly leaky with respect to gas. 

Where k is the permeability of reservoir rock to foam fracture fluid, AP is the differential pressure, is porosity, and fi is the viscosity of the foam fluid. 

Fig. 7. Log porosity versus depth for the Norphlet in two wells from Mobile Bay. (a) This well encountered an 18 m tight-zone. The transition from to porous reservoir rock is rapid occurring over the distance of a few metres, (b) The transition from tight-zone to reservoir in this well occurs over a long interval making the determination of the tight-zone base problematic. The interpreted base yields a tight-zone thickness of approximately 64 m for this well.

Type I (microporous) reservoirs They consist of oil-saturated siltstones interlayered with barren shales, siltstones, and also with dolomite and clay breccias. The porosities of the reservoir rock of this type range from 50 to 250 millidarcies. The oil recovery factor, as determined by many years of production experience, does not exceed 0.1. At present, the oil fields with this type of reservoir rock are not workable by conventional methods. 

With permeability values of 1400 Darcies and with oil viscosities of 2,0(X)-4,000 centipoise, the crude should have normal mobility in any reservoir rock characterized by macroporosity. The producing formations in the Abino-Ukrainsk field are essentially of this porosity type. Like the Zybza field, the Abino-Ukrainsk field also has some reservoir rocks of the microporosity type. Inasmuch as the oil in the reservoirs of the latter type is not mobile, only the oil-bearing horizons of macroporosity type are being worked during the early production stage of the field. 

Both the field experience with commercial scale production and the laboratory studies show that in cyclic steaming, best results are obtained when the reservoir is heated to a temperature of 120°C or higher. The amount of steam that must be injected into the reservoir during each "huff and puff treatment ranges from 1,000 to 1,500 tons. It depends on the porosity and permeability of reservoir rocks, the drilled thickness of the formation, arid the degree of its water fill. For each meter of effective thickness of the producing formation, 70-100 tons of steam should be-injected. 

The results of experimental studies carried out both in the U.S.A. [33] and in Russia indicate that the consumption of oxidizer (air) injected into the petroliferous bed during in situ combustion depends to a great extent on a number of factors. Among the latter can be listed the following the content of coke fuel within the volume of the treated bed, composition of the coke, CO2/CO ratio in the combustion gases the density of the crude oil, porosity and oil saturation of the reservoir rock, the temperature of combustion, and heat losses. 

The preservation of initially porous reservoir rocks especially at greater depths is above all a function of the thickness of the succession. The greater this is, the smaller will be the effect of compaction (Fig. 3.10). This phenomenon has been noted in numerous reservoirs studied and is encountered in different geological contexts. Furthermore, within a certain layer the porosity will increase from the top and the bottom towards its centre (Fig. 3.11). The statistical treatment of the respective data (Figs. 3.10,3.11) shows for different geological complexes in various basins of the Saharan Platform that ... 

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