Reservoir Rock Properties

1)            Porosity

                        The porosity is measure of the storage capacity (pore volume) that is capable of holding fluid. The mathematical relationship is the ratio between pore volume and the bulk volume. It can be further classified in to a) Absolute porosity, b) Effective porosity.

a)            Absolute porosity:

            Absolute porosity is the ratio between Total pore volumes to that of bulk volume.

b)           Effective porosity:

Effective porosity it the ratio between interconnected void spaces to the bulk volume of the rock.

The porosity genetically classified based on standard sedimentology description of reservoir rock are 1) primary porosity 2) secondary porosity.

Primary porosity:

             

Inter particle, in this type by which rock content was quickly lost in muds and carbonate and cementation respectively. This type is mostly silicastic sands.

           Intra particle porosity by which the porosity is made of interiors of carbonate skeletal grains.

Secondary porosity:

The porosity formed after deposition leads to other couple of reservoir types. Dissolution porosity type is made of carbonate dissolution and leaching. It is also called carbonate reservoirs.  Fracture porosity which is characterized by not being voluminous.

2)            Permeability:

The ability of the rock to allow the fluids to pass through the interconnected void spaces is nothing but the permeability. Moreover, a reservoir rock can be porous without being permeable. For example it is said to be permeable if and only if the pores “communicate”. Hence for explorationists, knowing reservoir rock permeability is a key mile stone because it’s important for being used to determine if it really has sufficient commercial accumulation of oil, indeed measuring it is very difficult.

            The measuring of permeability can differently be understood basing on two ways. When the porous medium is completely saturated by a single fluid, the permeability will be described Absolute, become described as Effective permeability when its porous medium is occupied by more than one fluid.

1)            Fluid saturation:

Saturation is defined as that fraction, or percent, of the pore volume occupied by a particular fluid (oil, gas, or water). This property is expressed mathematically by the ratio between the total volumes of the fluid to that of pore volume.

Major saturation types of interest in a reservoir are:

o    Critical oil saturation

o    Movable oil saturation

o    Residual  oil saturation

o    Connate water saturation

2)            Wettability:

This is the tendency of a fluid to spread on or adhere to a solid surface in the presence of other immiscible fluid. The angles made by the fluid with which it is in contact is known as the “contact angle”.

Depending on the type of fluid in contact with a sold surface, a reservoir could be; water-wet or oil-wet. Because of the attractive force, the wetting phase tends to occupy the smaller pores of the rock and the non-wetting phase occupies the more channels.

3)            Surface and Interfacial tension:

Petroleum reservoirs commonly have 2-3 fluids (multiphase systems).

It is necessary to consider the effect of the forces at the interface when two immiscible are in contact. When these two fluids are liquid and gas, the term surface tension is used to describe the forces acting at the interface. When the interface is between two liquids, the acting forces are called interfacial tension.

When 2 or more fluids are present, there are at least 3 sets of forces acting on the fluids and affecting HC recovery.

Immiscible fluids: when you bring them into contact they do not mix.

Two fluids are separated by an Interface.

The molecules are attracted more to their own kind.

4)            Capillary pressure:

  

When two immiscible fluids are in contact, a discontinuity in pressure exits between the two fluids, which depends upon the curvature of the interface separating the fluids. We call this pressure difference the capillary.

Similarly, it can be defined as the pressure differential between two immiscible fluid phases occupying the same pores caused by interfacial tension between the two phases that must be overcome to initiate flow. 

5)            Rock compressibility: 

Reservoir rocks are subjected to the internal stress exerted by fluids contained in the pores, and to external stress which is in part exerted by the overlying rocks.

The weight of the overburden simply applies a compressive force to the reservoir rock. Compressibility typically decreases with increasing porosity and effective pressure.

Porosity is a function of compaction. It is generally reduced by increase in compaction. Compaction is a function of burial.


Reference:  
1. Reservoir engineering Handbook, Tarek Ahmed
2. spe.org

by: Mohamed Azzarudeen M

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