Classification of permeability
Petroleum reservoirs can have primary permeability, which is also known as the matrix permeability and secondary permeability.Matrix permeability originated at the time of deposition and lithification (hardening) of sedimentary rocks. As with secondary (induced) porosity, secondary permeability resulted from the alteration of the rock matrix by: compaction, cementation, fracturing and solution. Whereas, compaction and cementation generally reduce the primary permeability; fracturingand solution tend to increase. In some reservoir rocks, particularly low-porosity carbonates, secondary permeability provides the main conduitfor fluid migration.
Factors affecting the magnitude of permeability
Permeability of petroleum reservoir rocks may range from 0.1 to 1000 or more millidarcies. The quality of a reservoir as determined by permeability in mD, may be judged as:
• K < 1 = poor
• 1< K = fair
• 10 < K < = moderate
• 50 < K < 250 = good
• K > 250 = very good
Reservoirs having permeability below 1 mD are considered "tight".Such low permeability values are generally found in limestone matrices and also in tight gas sands of western United States.
The factors affecting the magnitude of permeability in sediments are:
1. shape and size of sand grains:if the rock is composed of large and flat grains uniformly arranged with the longest dimension horizontally- its horizontal permeability (kH) will be very high, whereas, the vertical permeability(kv) will be medium-to-large. If the rock is composed mostly of large and uniformly rounded grains, its permeability will be considerably high and of the same magnitude in both directions. Permeability of reservoir rocks is generally lower, especially in the vertical direction, if the sand grains are small and of irregular shape. Most petroleum reservoirs are in this category. Reservoirs with directional permeabilityare called anisotropic. Anisotrophygreatly affects fluid flow characteristics. The difference in permeability measured parallel and vertical to the bedding plane is a consequence of the origin of that sediment. Subsequent compaction of the sediment increases the ordering of the sand grains so that they generally lie in the same direction;
2. cementation:of both permeability and porosity sedimentary rocks are influenced by the extent of cementation and the location of the cementing material within the pore space;
3. fracturing and solution: in sandstones, fracturing is not important cause of secondary permeability, except where sandstones are interbedded with shales, limestones and dolomites.
Capillary pressure
Capillary pressure is the difference in pressure between two immiscible fluids across a curved interface at equilibrium. Curvature of the interface is the consequence of preferential wetting of the capillary walls by one of the phases.
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Wettability
Wettabilityis the term used to describe the relative adhesionof two fluids to a solid surface. In a porous medium containing two or more immiscible fluids, wettabilty is a measure of the preferential tendency of one of the fluids to wet (spread or adhere) the surface.
In water-wet brine-oil-rock system, water will occupy the smaller pores and wet the major portion of the surfaces in the larger pores. In area of high oil saturation, the oil rests on a film of water spread over the surface. If the rock surface is preferentially water-wet and the rock is saturated with oil, water will imbibe into the smaller pores, displacing oil from the core when the system is in contact with water.
If the rock surface is preferentially oil-wet, even though it may be saturated with water, the core will imbibe oil into the smaller pores, displacing water from the core when it is contacted with water. Thus, a core saturated with oil is water-wet if it will imbibe water and, conversely, a core saturated with water is oil-wet if it will imbibe oil.
Actually, the wettability of a system can range from strongly water-wet to strongly oil-water depending on the brine-oil interactions with the rock surface. If no preference is shown by the rock to either fluid, the system is said to exhibit neutral wettability or intermediate wettability, a condition that one might visualize as being equally wet by both fluids (50% \ 50% wettability)
Other descriptive terms have evolved from the realization that components from the oil may wet selected areas throughout the rock surface. Thus, fractional wettability implies spotted, heterogeneous wetting of the surface, labeled "Dalmatian wetting" (by Brown and Fatt). Fractional wettability means that scattered areas throughout the rock are strongly wet by oil, whereas the rest of the area is strongly water-wet. Fractional wettability occurs when the surfaces of the rocks are composed of many minerals that have very different surface chemical properties, leading to variations in wettability throughout the internal surfaces of the pores. This concept is different from neutral wettability, which is used to imply that all portions of the rock have an equal preference for water or oil. Cores exhibiting fractional wettability will imbibe a small quantity of water when oil saturation is high and also will imbibe a small amount of oil when the water saturation is high.
The term "mixed wettability" commonly refers to the conditions where the smaller pores are occupied by water and are water-wet, but the larger pores of the rock are oil-wet and a continuous filament of oil exists throughout the core in the larger pores. Because the oil is located in the large pores of the rock in a continuous path, oil displacement from the core occurs even at very low oil saturation; hence, the residual oil saturation of mixed-wettability rocks is usually low.
Mixed wettability can occur when oil containing interfacially active polar organic compounds invade a water-wet rock saturated with brine. After displacing brine from the larger pores, the interfacially active compounds react with the rock surface, displacing the remaining aqueous film and, thus, producing an oil-wet lining in the large pores. The water film between the rock and the oil in the pore is stabilized by a double layer of electrostatic forces. As the thickness of the film is diminished by the invading oil, the electrostatic force balance is destroyed and the film ruptures, allowing the polar organic compounds to displace the remaining water and react directly with the rock surface.
Wettability has a profound influence on all types of fluid-rock interactions: capillary pressure, relative permeability, electrical properties, irreducible water saturation and residual oil and water saturations. On the other hand, the wettability is affected by minerals exposed to fluids in the pores of the rock, chemical constituents in the fluids and the saturation history of the samples. Wettability presents a serious problem for core analyses because drilling fluids and core-handling procedures may change the native-state wetting properties, leading to erroneous conclusions from laboratory tests.
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