Geophysical Characterization of Reservoir Pore Fluid Saturation

I briefly consider the nature of hydrocarbon saturation in reservoir pore spaces and how both seismic and electromagnetic data can characterize and quantify the nature of this saturation.

Fluids in a Rock

Oil or gas in a reservoir rock is not a simple case of a fluid occupying a space such that the fluid can occupy all the pore space (100% saturation) and then be completely replaced by water during reservoir production. Once a fluid migrates into a reservoir, it will never be completely removable. Hence, we talk about the ‘recovery factor’ determined from estimates of the residual oil/gas saturation after production and estimates of the original volumes of oil/gas in place.

A brief insight is offered into the complexity of how fluids occupy pore space, and how this may affect the detectability of hydrocarbons on both seismic and electromagnetics (EM) data.

As the following two figures schematically illustrate, a ‘water wet’ rock consists of some kind of rock matrix of varying grain sizes and mineralogies. These rock matrix assemblages can take many configurations. Consequently, there have been many analytical, heuristic and empirical relationships proposed over the years to relate elastic moduli, porosity and velocity. This is the science of rock physics. Simple applications include seismic AVO studies and seismic inversion to estimate elastic impedance attributes.

Note in particular that the figure below shows three liquid states: 1. ‘bound’ (or irreducible) water that will not be displaced by other fluids entering or leaving the pore space. If clay is present in the rock, some of the bound water is bound to the clay, often referred to as clay-bound water 2. ‘free’ water that is mobile, and 3. hydrocarbon (oil and/or gas).

Dual water model for shaly sands. Øh = hydrocarbon porosity, Øe = effective porosity, Øt = total porosity, Sh = hydrocarbon saturation, Sb = saturation of bound water, Sw = saturation of free water, Swt = saturation of free and bound water. To extend this explanation, the following figure illustrates common petrophysical terms related to shaly sands.

Note also in the next figure below that the same rock matrix can be ‘water wet’ (irreducible water) or ‘oil wet’ (irreducible oil). As a general rule, carbonate reservoirs are more prone to being oil wet than sandstone reservoirs. This is an important difference that affects how easily oil might be produced from a reservoir, and how successful both seismic and electromagnetic (EM) methods can be for detecting the properties of reservoir fluids and for monitoring changes in the physical state of the reservoir during depletion (i.e. hydrocarbon production).

Water-wet rock (left) vs. oil-wet rock (right). In the water-wet case, a film of water covers the mineral grains, and oil is only in contact with the water. In the oil-wet case, a film of oil covers the mineral grains, and water is only in contact with the oil. Oil-wet reservoirs have very low recovery rates.

When a ‘water wet’ reservoir matrix containing commercial hydrocarbons is produced the reservoir will eventually reach a physical state where there is insufficient ‘charge’ to deplete the reservoir any further, and a combination of residual oil and irreducible water remains.

How do Hydrocarbons Affect EM Data?

Electrical conductivity is only provided by the free water in the pore space and the bound water in the clays. Clays can form part of the rock matrix and they can also grow post-deposition in the pore spaces. The presence of clay minerals in a rock matrix causes unique conductivity properties that are influenced by the presence of brine (salty water).

Overall, the conductivity of clay is proportional to the bound water volume (‘water wet’ rock scenario). Thus, the bound water on clay affects the rock resistivity. Rock resistivity decreases with increasing porosity, following an exponential relationship.

Sandstones are mainly water-wet. Carbonates are often at least partially oil-wet, and sometimes entirely oil-wet. Gas is always non-wetting (never bound to grains). Water-wet reservoirs have good conductivity (low resistivity) and high recovery rates (low residual oil saturation after production). Oil-wet reservoirs have higher resistivity and low recovery rates. The most resistive reservoir rocks are carbonates, and the least resistive reservoir rocks are shaly sands.

Overall, we see now that the ‘bound’ fluid has a critical influence on the resistivity measured by EM data.

As the irreducible water saturation (‘Sb’; refer to the first figure above) decreases as grain size increases, an understanding of Sb can help understand reservoir quality.

A rock matrix with even grain sizes (‘well sorted’ during deposition) and high quartz mineralogy (i.e. sands) is more likely to have excellent pore space interconnectivity (‘permeability’) allowing hydrocarbons to freely flow out of the rock during production.

Carbonates with intense fracturing may also be excellent reservoirs. Permeability increases with increasing grain size. Finally, resistivity of brine decreases with increasing salinity and as temperature increases (associated with increasing depth), further complicating the physics.

How do Hydrocarbons Affect Seismic Data?

The physical properties of pore fluids and gas vary with temperature and pressure. Depending upon local physical property contrasts across either individual interfaces or an assemblage of thin layer interfaces, there may be an amplitude versus offset or angle (AVO/AVA) variation that is observable on pre-stack seismic gathers, and this AVA behavior may be unique wherever hydrocarbons are present. Or it may not.

Any rock matrix is a complex assemblage of different mineralogies, grain sizes, texture and cementation mechanisms.

As a general observation, gas is more easily identified by AVA anomalies than oil, particularly as oil may have similar physical properties to brine. The physical state of the oil/gas mixture in a reservoir is also important.

Gas is easily dissolved in oil thus drastically affecting the density and compressibility. Live oil (oil with dissolved gas) is always softer (more compressible) than dead oil (degassed oil). The measure of the amount of gas dissolved in oil is the gas-to-oil-ratio (GOR). The larger the GOR the larger the compressibility of oil. Local velocity anomalies may be useful hydrocarbon indicators, but changes in seismic velocity can work in opposing directions depending upon whether gas is being dissolved or coming out of solution.

As a further complication, hydrocarbon saturation may be inhomogenous (‘patchy’) through a reservoir. Seismic frequencies with wavelength greater than the patchiness scale will yield lower velocities than frequencies with wavelength smaller than the patchiness scale. These observations are further modified by dispersion, scattering and attenuation effects in the earth. Historically, the six properties sought by analysis of seismic amplitudes and velocities have been Lithology, Fluid (oil and/or gas), Porosity, Permeability, Pressure and Saturation of water, oil and gas.

Summary

Overall, there are many considerations when trying to establish the physical properties of fluids in a pore space at the microscopic, macro and reservoir scale. The complementary ways that EM and seismic measurements respond to the presence of fluids in a rock matrix may be rather complex, but they can be exploited via the use of rock physics and inversion of available geophysical data, calibrated wherever possible to in-situ measurements from well data. From the perspective of seismic acquisition and processing, data fidelity and frequency content is obviously critical. Quantitative predictions involve considerable uncertainty and risk – factors we attempt to assist with good survey design and execution, followed by careful data processing.

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