Reservoir rocks

Free sulfur is rarely present in crude oils, but it can be found in suspension or dissolved in the liquid. The crude from Goldsmith (Texas, USA.) is richest in free sulfur (1% by weight for a total sulfur content of 2.17%). It could be produced by compounds in the reservoir rock by sulfate reduction (reaction 8.2). 

Keywords plate tectonics, sedimentary basins, source rocks, maturation, migration, reservoir rocks, traps, seismic, gravity survey, magnetic survey, geochemistry, mudlogs, field studies. 

Migration describes the process which has transported the generated hydrocarbons into a porous type of sediment, the reservoir rock. Only if the reservoir is deformed in a favourable shape or if it is laterally grading into an impermeable formation does a trap for the migrating hydrocarbons exist. 

Reservoir rocks are either of clastic or carbonate composition. The former are composed of silicates, usually sandstone, the latter of biogenetically derived detritus, such as coral or shell fragments. There are some important differences between the two rock types which affect the quality of the reservoir and its interaction with fluids which flow through them. 

Carbonate reservoir rock is usually found at the place of formation ( in situ ). Carbonate rocks are susceptible to alteration by the processes of diagenesis. 

The pores between the rock components, e.g. the sand grains in a sandstone reservoir, will initially be filled with the pore water. The migrating hydrocarbons will displace the water and thus gradually fill the reservoir. For a reservoir to be effective, the pores need to be in communication to allow migration, and also need to allow flow towards the borehole once a well is drilled into the structure. The pore space is referred to as porosity in oil field terms. Permeability measures the ability of a rock to allow fluid flow through its pore system. A reservoir rock which has some porosity but too low a permeability to allow fluid flow is termed tight . 

In Section 5.1 we will examine the properties and lateral distribution of reservoir rocks in detail. 

With a few exceptions reservoir rocks are sediments. The two main categories are siliciclastic rocks, usually referred to as elastics or sandstones , and carbonate rocks. Most reservoirs in the Gulf of Mexico and the North Sea are contained in a clastic depositional environment many of the giant fields of the Middle East are contained in carbonate rocks. Before looking at the significance of depositional environments for the production process let us investigate some of the main characteristics of both categories. 

Carbonate rocks are not normally transported over long distances, and we find carbonate reservoir rocks mostly at the location of origin, in situ . They are usually the product of marine organisms. However, carbonates are often severely affected by diagenetic processes. A more detailed description of altered carbonates and their reservoir properties is given below in the description of diagenesis . 

Figure 5.5 The stress - strain diagram for a reservoir rock...

Juxtaposition faulting has resulted in an impermeable rock juxtaposed against a reservoir rock. 

It is believed that the majority of clastic reservoir rocks are water wet, but the subject of wettability is a contentious one. 

This is consistent with the observation that the largest difference between the oil-water interface and the free water level (FWL) occurs in the narrowest capillaries, where the capillary pressure is greatest. In the tighter reservoir rocks, which contain the narrower capillaries, the difference between the oil-water interface and the FWL is larger. 

To gain an understanding of the composition of the reservoir rock, inter-reservoir seals and the reservoir pore system it is desirable to obtain an undisturbed and continuous reservoir core sample. Cores are also used to establish physical rock properties by direct measurements in a laboratory. They allow description of the depositional environment, sedimentary features and the diagenetic history of the sequence. 

In nearly all oil or gas reservoirs there are layers which do not contain, or will not produce reservoir fluids. These layers may have no porosity or limited permeability and are generally defined as non reservoir intervals. The thickness of productive (net) reservoir rock within the total (gross) reservoir thickness is termed the net-to-gross or N/G ratio. 

Nearly all reservoirs are water bearing prior to hydrocarbon charge. As hydrocarbons migrate into a trap they displace the water from the reservoir, but not completely. Water remains trapped in small pore throats and pore spaces. In 1942 Arch/ e developed an equation describing the relationship between the electrical conductivity of reservoir rock and the properties of its pore system and pore fluids. 

Reservoir engineers describe the relationship between the volume of fluids produced, the compressibility of the fluids and the reservoir pressure using material balance techniques. This approach treats the reservoir system like a tank, filled with oil, water, gas, and reservoir rock in the appropriate volumes, but without regard to the distribution of the fluids (i.e. the detailed movement of fluids inside the system). Material balance uses the PVT properties of the fluids described in Section 5.2.6, and accounts for the variations of fluid properties with pressure. The technique is firstly useful in predicting how reservoir pressure will respond to production. Secondly, material balance can be used to reduce uncertainty in volumetries by measuring reservoir pressure and cumulative production during the producing phase of the field life. An example of the simplest material balance equation for an oil reservoir above the bubble point will be shown In the next section. 

Figure 8.14 Single fluid flowing through a section of reservoir rock...

For a single fluid flowing through a section of reservoir rock, Darcy showed that the superficial velocity of the fluid (u) is proportional to the pressure drop applied (the hydrodynamic pressure gradient), and inversely proportional to the viscosity of the fluid. The constant of proportionality is called the absolute permeability which is a rock property, and is dependent upon the pore size distribution. The superficial velocity is the average flowrate... 

The above experiment was conducted for a single fluid only. In hydrocarbon reservoirs there is always connate water present, and commonly two fluids are competing for the same pore space (e.g. water and oil in water drive). The permeability of one of the fluids is then described by its relative permeability (k ), which is a function of the saturation of the fluid. Relative permeabilities are measured in the laboratory on reservoir rock samples using reservoir fluids. The following diagram shows an example of a relative permeability curve for oil and water. For example, at a given water saturation (SJ, the permeability... 

Reservoir simulation is a technique in which a computer-based mathematical representation of the reservoir is constructed and then used to predict its dynamic behaviour. The reservoir is gridded up into a number of grid blocks. The reservoir rock properties (porosity, saturation, and permeability), and the fluid properties (viscosity and the PVT properties) are specified for each grid block. 

Field analogues should be based on reservoir rock type (e.g. tight sandstone, fractured carbonate), fluid type, and environment of deposition. This technique should not be overlooked, especially where little information is available, such as at the exploration stage. Summary charts such as the one shown in Figure 8.19 may be used in conjunction with estimates of macroscopic sweep efficiency (which will depend upon well density and positioning, reservoir homogeneity, offtake rate and fluid type) and microscopic displacement efficiency (which may be estimated if core measurements of residual oil saturation are available). 

Fig. 11. Water consumption during extended pressurization of an HDR reservoir. The amount of water required to maintain a constant pressure declines with the logarithm of time as the microcracks in the reservoir rock are slowly filled with the pressurized fluid.

As reservoir pressure is reduced by oil production, additional recovery mechanisms may operate. One such mechanism is natural water drive. Water from an adjacent more highly pressured formation is forced into the oil-bearing formation by the pressure differential between the formations. Another mechanism is gas drive. Expansion of a gas cap above the oil as oil pressure declines can also drive additional oil to the wellbore. Produced gas may be reinjected to maintain gas cap pressure as is done on the Alaskan North Slope. Additional oil may also be produced by compaction of the reservoir rock as oil production reduces reservoir pressure. 

Thermal stabihty of the foaming agent in the presence of high temperature steam is essential. Alkylaromatic sulfonates possess superior chemical stabihty at elevated temperatures (205,206). However, alpha-olefin sulfonates have sufficient chemical stabihty to justify their use at steam temperatures characteristic of most U.S. steamflood operations. Decomposition is a desulfonation process which is first order in both surfactant and acid concentrations (206). Because acid is generated in the decomposition, the process is autocatalytic. However, reservoir rock has a substantial buffering effect. 

By 1980, research and development shifted from relatively inexpensive surfactants such as petroleum sulfonates to more cosdy but more effective surfactants tailored to reservoir and cmde oil properties. Critical surfactant issues are performance in saline injection waters, adsorption on reservoir rock, partitioning into reservoir cmde oil, chemical stabiUty in the reservoir, interactions with the mobiUty control polymer, and production problems caused by resultant emulsions. Reservoir heterogeneity can also greatly reduce process effectiveness. The decline in oil prices in the early 1980s halted much of the work because of the relatively high cost of micellar processes. 

Microbes adsorb and grow on reservoir rock surfaces fed by injected nutrients (271) and may have appHcation in plugging thief zones near injection... 

Once the potential for hydrocarbons has been verified in a region, explorationists look for reservoir rocks that potentially contain the hydrocarbons. Reservoir rocks are typically comprised of sands or carbonates that have space, called porosity, tor... 

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