Types of Caprocks in Petroleum System

Cap rock

Caprock is a rock that prevents the flow of a given fluid at a certain temperature and pressure and geochemical conditions. 

For a long time, the only force causing the movement of oil and gas in the subsurface was believed to be buoyancy. If so, then to form oil and gas accumulation, their migration paths must have been stopped by a roof, i.e., caprock (seal). Clays, shales, carbonates, evaporites, and their combinations can form caprocks. The same rocks react differently to different fluids. In some cases, rocks serve as satisfactory or good conduits for water, but form barriers for oil or gas movement. In some other situations rocks yield oil but stop gas movement, etc. This is determined by capillary forces, the magnitude of which depends on fluid and rock properties (fluid density, fluid viscosity, rock structure, rock wettability) and pore size (capillary forces almost disappear when the pore diameter exceeds 0.5mm). All aforementioned rock and fluid properties are strongly affected by the subsurface temperature and pressure and geochemical environment. Caprock is a rock that prevents the flow of a given fluid at a certain temperature and pressure and geochemical conditions. Therefore, the necessary properties of a rock to act as a seal will be different for different fluids. The same rock with different fluids may or may not have sealing properties up to a complete inversion (caprock - reservoir). The caprocks can be categorized into three types. 

Type I caprocks are typical for argillaceous sequences in a state of continuing compaction; they are developed in areas of young subsidence of Earth’s crust, with abnormally high pore water pressure. Sealing properties of these rocks are determined by the amount of capillary pressure at the contact of the reservoir and caprock, the pore pressure of water saturating the caprock, initial pressure gradient of water and the variation of hydraulic forces in the section. Oil and gas accumulations have higher potential energy than that of the formation water. These accumulations can be stable only if this energy is equal to or less than the caprock breakthrough energy. Pore water pressure in compacting argillaceous beds is always greater than the pressure in the adjacent reservoir beds. As a result, sealing capability of the Type I caprocks is determined by hydraulic sealing, by the amount of capillary pressure, and by the pressure at which water begins to flow through caprocks. Just the capillary pressure alone in such caprocks may exceed 100kg/cm2. This means that the Type I caprocks is capable of confining an oil accumulation having almost any column height. It appears that sealing capability of argillaceous caprocks does not depend on their thickness describes only the aforementioned caprock type.  

Type II caprocks are associated with rocks compacted beyond the plasticity limit and having lost ability to swell on contact with water. Such rocks do not contain swelling clay minerals, and interstitial water contains surfactants. Consequently, pore water in these rocks does not have initial pressure gradient. This type of caprocks is encountered mostly in the Paleozoic and Mesozoic sediments of young and old platforms. There are no clear-cut overpressure environments there, but there is a relatively clear hydrodynamic subdivision in the section. the hydrodynamic environment may improve or lower the sealing capability of caprocks. In an extreme case, the water potential in the reservoir may exceed the water potential of the bed overlying the caprock by the value of capillary pressure. In such a situation, the caprock will be open for the vertical flow of hydrocarbons, and the trap will not exist even when potential distribution in the reservoir bed is favorable. 

Type III caprocks are typical for rocks with a rigid matrix and intense fracturing. Such caprocks are mainly developed over the old platforms in regions of low tectonic mobility, with no detectable hydrodynamic breakdown of the section. Formation water potential in such regions is practically equal throughout the section and corresponds to the calculated hydrostatic potential. 

The correlation between clay mineralogy and their sealing properties are as follows "The permanency in the composition of the silicate layer is a characteristic of the kaolinite group minerals. As a result, replacements within the lattice are very rare and the charges within a layer are compensated. The connection between silicate layers in the C-axis direction is implemented through hydrogen atoms, which prevents the lattice from expanding, ruling out the penetration of water and polar organic liquids. The silicate layer in the montmorillonite mineral group is variable due to a common isomorphic replacement in octahedral and narrower tetrahedral sheets. This replacement results in the disruption of the lattice neutrality. Extra charge that occurs with such replacements is compensated by exchange ions. Ion properties that maintain lattice neutrality in montmorillonite minerals (valence, size of the ion radius, polarization, etc.) define the capability of the lattice to expand along the C-axis. As a result, water and polar organic liquids can penetrate the interlayer spaces. This, in turn, leads to an increase in the volume, which drastically lowers permeability and some other properties, but at the same time improves sealing capabilities. The silicate layer of the illite mineral group is similar to the montmorillonite one. However, the excessive negative charge of the lattice is due mainly to the isomorphic replacements within tetrahedral sheets. The proximity between the source of negative charge and basal surfaces causes a stronger connection between the silicate layers of illite group compared to montmorillonite’s." 

Admixture of sand and silt degrades the sealing properties of clays. Especially important are the textural changes due to this admixture. Not only the mineral composition of a rock and organic matter content, but also the pore water are important in forming the major sealing properties of clays, such as degree of swelling and compressibility. The relatively low-temperature pore water is retained in argillaceous rocks up to a temperature of 100C to 150C. The temperature of water removal is higher when the concentration of dissolved components is higher. Pore water is located within pores of argillaceous rocks, and at the surfaces and along the edges of individual microblocks and microaggregates that comprise clays. The interlayer water causes swelling in montmorillonites and in degraded illites. The order in water molecules positioning, relative to the clay mineral blocks and aggregates, is rapidly altered with an increase in distance between these blocks and aggregates. Thus, a very important information for the evaluation of the role water plays in the formation of sealing properties is the knowledge of the structural status of the layer in an immediate contact with the particles surface, and the role the cations having different charge density play in the preservation of water molecules structure. Exchange ions play a leading role in the formation of "water clouds" around microaggregates and microblocks of montmorillonite minerals and an insignificant role, with kaolinite minerals. The role played by the illite group minerals occupies an intermediate position. Carbonates caprocks include micro- and fine-grained, massive and laminated limestones. Almost all limestones are dolomitized to some extent and are subject to fracturing. This adversely affects their sealing properties. Carbonates with a substantial clay content have laminated texture. As a rule, this results in a deterioration rather than an improvement of sealing properties due to the emergence of weakness zones at the contact between different lithologies. Evaporite seals, which are common, include salt, anhydrite, and sometimes shales. It is a common (and probably erroneous) belief that such seals are the best and most reliable. Brittleness of these rocks at the surface conditions contradicts that belief. Besides, cores recovered in the Dnieper-Donets Basin and North Caspian Basin display macro- and microscopic fractures, which sometimes cut monolithic salt crystals. The fractures may be healed by secondary salt, but often contain traces of oil and sometimes gas bubbles. Sometimes core samples are completely saturated with oil. Permeability measured at the surface conditions can reach 100–150mD and even higher. It was established, however, that these rocks easily become plastic even at a relatively low hydrostatic or, even, uniaxial pressure (o100MPa) and the properties change with temperature. Some people considered plasticity as an important sealing property. In this connection, they believe that salt has the best sealing properties. They also believe that the reliability of caprock is not directly related to its thickness. Thus, properties of evaporites as seals change widely during the catagenesis (and in time). Similar changes also affect the other types of seals albeit not so obviously. Inclusions, such as organic matter, silt, clay or carbonate particles degrade sealing properties of evaporites due to the formation of zones of weakness around such inclusions. A careful study of numerous logs from Dnieper-Donets Basin showed the presence of clay interbeds between the top of accumulation and the evaporite sequence in all cases. It appears that these interbeds in most cases act as caprock.