Reservoir Engineering | Basic Concepts in Reservoir Engineering

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Reservoir simulation, Fluid flow, Petrophysics, Formation evaluation, Well testing, Enhanced oil recovery, Geostatistics, Pore pressure prediction, Porosity, Permeability, Saturation, Well performance, Well logging, Reservoir characterization, Reservoir management, Reservoir modeling, Production optimization, Water flooding, Gas reservoirs, Oil reservoirs, Reservoir monitoring, Reservoir analysis, Well spacing, Reservoir performance, Reservoir geomechanics, Basic concepts of reservoir engineering, Basic concepts of civil engineering, What is reservoir engineering, 3 types of reservoir, Reservoir engineering basics, Reservoir engineering pdf, Reservoir engineering handbook pdf, Basic concepts of environmental engineering

Porosity, Permeability and Fluid Saturation

Porosity is defined as the ratio of the pore space in the rock to the bulk volume of the rock. It is expressed as a fraction or as a percent of the bulk volume. In equation form,

$\phi =\dfrac{V_{p}}{V_{b}}$ ………… (7)

ϕ = porosity (fraction)

V_p = pore volume

V_b = bulk volume

V_p and V_b can be in any consistent units.

Two types of porosity can exist in the rock: total and effective. Total porosity comprises all of the pore spaces, including connected spaces, isolated spaces (e.g., vugs or fractures) and, in shaly formations, water which is bound to clay minerals. Effective porosity refers only to the interconnected pore spaces, although among some companies it is more strictly defined as interconnected porostiy without clay-bound water). While it is effective porosity that is of primary interest to reservoir engineers, a knowledge of total porosity is also important with respect to reservoir description and characterization. In some reservoirs (e.g., clean, unfractured sandstones), the difference between the total and effective porosity will be negligible; in others (e.g., highly vuggy carbonates or very shaly sands), the difference may be significant.

Various methods exist for measuring porosity. Some are based on measurements of a rock sample’s bulk volume and solid volume, and obtain the pore volume by subtracting the solid from the bulk volume. Thus: [pore volume=bulk volume−solid volume]. Other methods are based on measuring the pore volume directly in addition to the bulk volume. Such methods utilize gas expansion, fluid saturation, or mercury injection. Porosity measured by these techniques is the effective porosity.

Permeability is a measure of the ability of porous rock to transmit fluid. The quantitative value for this characteristic is the permeability. The permeability may be absolute or effective.

Absolute permeability occurs when only one fluid is present in the rock. It is a property of the rock and should be independent of the fluid used in the measurement. This assumes that the fluid does not interact with the rock. Absolute permeability is calculated by Darcy’s law using laboratory-measured data. The unit of the permeability is the darcy. The permeability of one darcy may be defined as that permeability which will allow the flow of one $\tfrac{cm^3}{s}$ of a fluid of viscosity one centipoise through a rock sample of one cm² in cross-sectional area under a pressure gradient of one atmosphere per cm. A permeability of one darcy is a large value, and we normally use the unit of millidarcy (0.001 darcy) to describe the permeability of most reservoirs. In some reservoirs the permeability may be as low as a fraction of a millidarcy, while in others it may be several darcies. The well-flow rate is directly proportional to permeability. Thus, wells with very low permeabilities are normally marginally productive, and may require stimulation and remedial action to improve their production.

Effective permeability occurs when more than one fluid is present: it is a function of the fluid saturation. Therefore, one speaks of effective permeability to oil, water, and gas. Effective permeability cannot be higher than absolute permeability. The ratio of effective to absolute permeability is termed relative permeability.

Saturation is a measure of the relative volume of each fluid in the pores. Thus the oil saturation is defined as the ratio of the volume of the oil in a porous rock to the pore volume of the same rock. It is expressed in fraction or in percent, and ranges from 0 to nearly 100%. Water is always present in all reservoirs, and its saturation is always greater than zero. In contrast, the oil saturation is zero in gas reservoirs, and the gas saturation is zero in oil reservoirs when the pressure is above the bubble-point. The water saturation is normally obtained in situ from log data. The oil or gas saturation is then calculated by subtracting the water saturation from unity (in two-phase reservoirs).

Sometimes the fluid content and saturations are measured directly in the laboratory on fresh core samples. These cores are obtained using an oil-base drilling fluid, and considerable care will have been exercised during the coring operation.

Oil or gas saturations are needed to volumetrically calculate the initial oil or gas in place.