4.2. Optimisation of the Parameters for Preparation of Single Layer
4.2.2. Effect of an Annealing Step on the Contact
4.6 Porosity Estimation from Well Logs
Porosity of reservoir rock can be estimated not only by using methods, as has been described above, but also from geophysical well logs, often called wireline logs. This method of porosity evaluation is not very accurate, but has the advantage of providing continous porosity data.
Once these logs are obtained and converted into a porosity log, they can be calibrated using core-sample porisity data and serve as additional reliable source of porosity distribution evalu-ation.
Porosity can be estimated from:
• Formation resistivity factor (F).
• Microresistivity log (from which F can be derived).
• Neutron - gamma log.
• Density (gamma - gamma) log.
• Acoustic (sonic) log.
The Formation resistivity factor is defined as the ratio of the resistivity of the porous sample saturated with an ionic solution Roof the bulk resistivity of the same solution Rw, i.e. [23]
F = Ro
Rw. (4.6)
The Formation resistivity factor measures the influence of pore structure on the resistance of the core sample. There are several relationships which can be used for the porosity evaluation using F-values [23],
• F =φ−m, where m is the cementation constant (Archie, 1942).
• F = (3 −φ)/2φ (Maxwell, 1881).
• F = X /φ, where X is the electric tortuosity of the sample (Wyllie, 1957).
For more information regarding porosity evaluation using geophysical well logs, see refer-ence [7, 23, 37].
4.7 Exercises
1. Calculate the bulk volume of a preserved (paraffin-coated) core sample immersed in water, given the following data:
weight of dry sample in air: 20 g,
weight of dry sample coated with paraffin: 20.9 g (density of paraffin is : 0.9 g/cc), weight of coated sample immersed in water: 10 g (density of water is: 1g/cc) Determine the rock’s porosity, assuming a sand-grain density of 2.67 g/cc.
2. Calculate the bulk volume of a dry core sample immersed in mercury pycnometer, given the following data:
weight of dry sample in air: 20 g,
weight of mercury-filled pycnometer at 20oC: 350 g,
weight of mercury-filled pycnometer with the sample at 20oC; 235.9 g.
density of mercury: 13.546 g/cc.
3. Determine the sandstone’s grain density and porosity, given the following data:
weight of crushed dry sample in air: 16 g,
weight of crushed sample plus absorbed water: 16.1 g, weight of water-filled pycnometer: 65 g,
weight of water-filled pycnometer with the sample: 75 g.
4. Determine the sandstone’s grain volume and porosity using Boyl’s law, given the follow-ing data:
volume of chamber containing the core sample: 15 cc, volume of chamber containing air: 7 cc,
bulk volume of core sample: 10 cc
5. Calculate the effective porosity of a sandstone sample using the following data:
weight of dry sample in air: 20 g, weight of saturated sample in air: 22.5 g, density of water is : 1.0 g/cc),
weight of saturated sample in water: 12.6 g.
6. A core sample is saturated with an oil (ρo= 35oAPI), gas and water. The initial weight of the sample is 224.14 g. After the gas is displaced by water (ρw= 1 g/cm3), the weight is increased to 225.90 g. The sample is the placed in aSoxhlet distillation apparatus, and 4.4 cm3 water is extracted. After drying the core sample, the weight is now 209.75 g.
The sample bulk volume, 95 cm3is measured in a mercury pycnometer.
Find the porosity, water saturation, oil saturation, gas saturation and lithology of the core sample. (Notice that the oil density isρ[g/cm3] = 141.4/(131.5 +ρ[oAPI]), when the water density at that particular temperature and pressure is 1g/cm3)
7. Another core sample is brought to the laboratory for compositional analysis, where 80 g of the sample is placed in a mercury pycnometer and the volume of gas found is 0.53 cm3. A piece of the same sample, weighing 120 g is placed in a retorte, where the water and oil volume is measured to 2.8 cm3 and 4.4 m3, respectively. A third piece of the
sample, weighing 90 g is placed in a pycnometer and the bulk volume is measured to be 37.4 cm3. Assume oil and water densities as in the exercise above and find the same characteristic parameters.
8. Calculate the porosity of the sample described below:
mass of dry sample: 104.2 g,
mass of water saturated sample: 120.2 g, density of water 1.001 g/cm3,
mas of saturated sample immersed in water: 64.7 g.
Is this effective porosity or the total porosity of the sample? What is the most probable lithology of the matrix material? Explain .
9. A core, 2.54 cm long and 2.54 cm in diameter has a porosity of 22%. It is saturated with oil and water, where the oil content is 1.5 cm3.
a) What is the pore volume of the core?
b) What are the oil and water saturations of the core?
10. If a formation is 2.5 m thick, what is the volume of oil-in-place (in m3 and in bbl) of a 40.47 hectare large area, if the core described in the excercise above is representative of the reservoir?
Answer to questions:
1. 24.3%, 2. 9.95 cm3, 3. 2.67 g/cm3, 1.6%, 4. 20%, 5. 25%, 6. 19%, 14.5%, 75.8%, 9.6%, 2.73 g/cm3, 7. 16%, 35.1%, 55.1%,10%, 2.69 g/cm3, 8. 29%, 2.64 g/cm3, 9. 2.831 cm3, 53%, 47%, 10. 738235.6 bbl
Permeability
5.1 Introduction
Permeability in a reservoir rock is associated with it’s capacity to transport fluids through a system of interconnected pores, i.e. communication of interstices. In general terms, the per-meability is a tensor, since the resistance towards fluid flow will vary, depending on the flow direction. In practical terms, however, permeability is often considered to be a scalar, even though this is only correct for isotropic porous media.
If there were no interconnected pores, the rock would be impermeable, i.e., it is natural to assume that there exists certain correlations between permeability and effective porosity.
All factors affecting porosity will affect permeability and since rock permeability is difficult to measure in the reservoir, porosity correlated permeabilities are often used in extrapolating reservoir permeability between wells.
Absolute permeability could be determined in the laboratory by using inert gas (nitrogen is frequently used) that fills the porous rock sample completely and limits the possibility of chemical interaction with the rock material to a minimum. Since the gas molecules will pen-etrate even the smallest pore-throats, all pore channels are included in the averaging process when permeability is measured.
When several phases or mixtures of fluids are passing through a rock locally and simulta-neously, each fluid phase will counteract the free flow of the other phase’s and a reduced phase permeability (relative to absolute) is measured, i.e. effective permeability.