Properties of reservoir rocks

PorosityPermeability

Fluid saturation Mahboob Ahmed

Porosity

Ratio of the volume of space to the total volume of a rock. Porosity of a rock is a measure of its ability to hold a fluid. Porosity is expressed as a percentage of the total rock which is taken up by pore

space. a sandstone may have 8% porosity. This means 92 percent is solid rock and 8 percent is open space containing oil,

gas, or water

Total porosity the ratio of the entire pore space in a rock to its bulk volume. Effective porosity percent of bulk volume occupied by interconnected pores spaces. A total porosity less the fraction of the pore space occupied by shale or

clay In very clean sands, total porosity is equal to effective porosity.

Primary porosity

porosity of the rock that formed at the time of its deposition. primary porosity of a sediment or rock consists of the spaces between the

grains. Primary porosity decrease due compaction and packing of grains. Intergranular pores of clastics or carbonates. Primary porosity less than one percent in crystalline rocks like granite. more than 55% in some soils.

Secondary porosity develops after deposition of the rock. Vugular spaces in carbonate rocks created by the chemical process of

leaching. fracture spaces formed due to stress distortion in reservoirs rocks.

Porosity in sandstone

• Sandstone usually has regular grains; and is referred to as a grainstone.

• Porosity Determined mainly by the packing and mixing of grains.

• Fractures may be present.

Porosity in Sandstone

The porosity of a sandstone depends on the packing arrangement of its grains.

Grain-Size Sorting in Sandstone

SANDSTONES POROSITY TYPES

Intergranular (Primary)Interstitial Void Space Between Framework Grains.

MicroporesSmall Pores Mainly Between detrital Framework Grains or Cement.

DissolutionPartial or Complete Dissolution of or Authigenic Grains (Can Also Occur

Within Grains)

FracturesBreakage Due to Earth Stresses.

CARBONATES POROSITY TYPES

Interparticle porosity Each grain is separated, giving

a similar pore space arrangement as sandstone.

Intergranular porosity Pore space is created inside

the individual grains which are interconnected.

Intercrystalline porosity Produced by spaces between

carbonate crystals.

Mouldic porosity Pores created by the

dissolution of shells, etc.

CARBONATES POROSITY TYPES

Fractured porosity Pore spacing created by the cracking

of the rock fabric.

Channel porosity Similar to fracture porosity but larger.

Vuggy porosity Created by the dissolution of

fragments, but unconnected.

Permeability

The rate of flow of a liquid through a formation depends on: – The pressure drop. – The viscosity of the fluid. – The permeability. Permeability measures the capacity and ability of the formation to

transmit fluids.

it controls the directional movement and the flow rate of the reservoir fluids in the formation.

The unit of measurement is the Darcy.

Reservoir permeability is usually quoted in millidarcies, (md).

DARCY LAWK = permeability, in Darcies.

L = length of the section of rock, in centimetres.

Q = flow rate in centimetres / sec.

P1, P2 = pressures in bars. A = surface area, in cm2. μ = viscocity in centipoise.

types permeability

Absolute Permeability

When the medium is completely saturated with one fluid, then the permeability measurement is often referred to as specific or absolute permeability

Effective Permeability

When the rock pore spaces contain more than one fluid, then the permeability to a particular fluid is called the effective permeability. Effective permeability is a measure of the fluid conductance capacity of a porous medium to a particular fluid when the medium is saturated with more than one fluid

Relative Permeability

Defined as the ratio of the effective permeability to a fluid at a given saturation to the effective permeability to that fluid at 100% saturation.

PERMEABILITY AND ROCKSIn formations with large grains, the permeability is

high and the flow rate larger.The permeability in the horizontal direction is controlled by the

large grains.

In a rock with small grains the permeability is less and the flow lower. The permeability in the vertical direction is controlled by the small grains

Grain size has no bearing on porosity, but has a large effect on permeability.

CLASTIC RESERVOIRS

Permeability• Determined mainly by grain size

and packing, connectivity and shale content.

CARBONATE RESERVOIRS

Permeability Determined by deposition

and post deposition events, fractures.

FLUIDS IN A RESERVOIR

A reservoir normally contains either water or hydrocarbon or a mixture.

The hydrocarbon may be in the form of oil or gas.

The specific hydrocarbon produced depends on the reservoir pressure and temperature.

The formation water may be fresh or salty.

The amount and type of fluid produced depends on the initial reservoir pressure, rock properties and the drive mechanism.

Initially, pore space filled 100% with water

Connate water saturation remains in hydrocarbon zone.

Critical oil saturation, Soc

For the oil phase to flow, the saturation of the oil must exceed a certain value which is termed critical oil saturation. At this particular saturation, the oil remains in the pores and, for all practical purposes, will not flow.

Movable oil saturation, Som

Movable oil saturation Som is another saturation of interest and is defined

as the fraction of pore volume occupied by movable oil as expressed by

the following equation:

Som = 1 - Swc - Soc

where

Swc = connate water saturation

Soc = critical oil saturation

Critical gas saturation, Sgc

As the reservoir pressure declines below the bubble-point pressure, gas evolves from the oil phase and consequently the saturation of the gas increases as the reservoir pressure declines. The gas phase remains immobile until its saturation exceeds a certain saturation, called critical gas saturation, above which gas begins to move.

Critical water saturation, Swc The critical water saturation, connate water saturation, and

irreducible water saturation are extensively used interchangeably to define the maximum water saturation at which the water phase will remain immobile.