- Let's look now at some examples of secondary control factors on oil quality, fluid properties, and/or volume of the accumulation. The term secondary here is used to indicate post-accumulation, in-reservoir processes that could alter oil quality, fluid properties, and/or volume of the hydrocarbon accumulation rather than secondary in importance processes. Biodegradation, water washing, and trap leakage are three examples of such secondary, post-accumulation processes that could be recognized by geochemistry studies. Biodegradation is the process of decomposition of petroleum organic compounds by microorganisms. Biodegradation processes proceed if reservoir temperature is lower than 80 degree centigrade or approximately 176 degree Fahrenheit. The destruction of petroleum compounds proceeds from shorter to longer carbon number compounds and from simpler, for example, n-alkanes, to more complex molecular structures, for example, steranes or aromatics. Biodegradation rank is based on the sequential destruction of organic compounds in the oil by microorganisms, as illustrated in the figure to the left from Peters and Moldowan, 1993. Trap topology and water leg extent are additional control factors on nutrient supply and net biodegradation, as discussed by Larter et al., 2006. Biodegradation effects on oil composition and fluid properties could be pretty significant. The figure illustrates three gas chromatograms of oils with different level of biodegradation, slight biodegradation at the top, moderate biodegradation in the middle, and very heavy biodegradation rank at the bottom. Note the significant decrease in oil API gravity as biodegradation rank increases from slight, the oil is still with 39 API gravity, to very heavy, the oil gravity is now at 19 degree. In parallel to decreasing API gravity or increasing density of the oil, the oil viscosity increases, as well as the sulfur and asphaltene contents of the oil. Let's talk about another process often associated with biodegradation that could impact fluid properties, namely this is the process of water washing. On a regional scale, water flow through permeable carriers in the subsurface is driven by a hydraulic head that commonly occurs by uplift on a basin margin. The figure on the left shows schematic geologic model for water washing of crude oils with and without bacterial degradation. Reservoir biodegradation is usually accompanied by water washing, which provides the oxygen and nutrients for biodegradation to occur at temperatures lower than 80 degree centigrade. This is zone A on the figure. Water washing may occur without biodegradation at temperatures higher than 80 degree C, which would be the zone B on the figure, and/or absence of oxygen, which would be zone C on the figure. However, it should be noted that this model, especially for zone C, assumes aerobic biodegradation only, which is not always the case. Water washing could occur during petroleum migration or in the reservoir. We'll be focusing here on reservoir water washing, which is a petroleum alteration process taking place in the reservoir, close to the oil-water contact. Reservoir water washing involves the preferential dissolution of components with higher water solubility from the oil accumulation into the associated aquifer. The figure illustrates the water solubility of different classes hydrocarbons, normal alkanes, cycloalkanes, and aromatics, as a function of carbon number. Note that benzene and toluene are light aromatics with highest water solubility, much higher than the nC7 alkane. Due to their highest water solubility, benzene and toluene would be preferentially removed from the oil under reservoir water washing conditions. Therefore, depletion in the ratios of benzene to nC6 alkane or toluene to nC7 alkane of an oil is considered as indication of water washing. Water washing tends to reduce, in general, the API gravity of the oil. Here is a field case study illustrating the ratio of toluene to nC7 alkane for different parts of the same basin. Note that almost all oil data show values for the toluene/nC7 alkane ratio higher than .20 to .23, and there are only two areas in the basin, which show lower toluene/nC7 ratio, which indicates water washing effects. These two areas are located towards the periphery of the basin where the reservoir is approaching a discharge zone, and thus the geochemistry observations are consistent with the geological model. Let's talk about trap leakage and the impact of phase fractionation processes on fluid properties. The impact of different phase fractionation processes on fluid composition and properties has been studied for over 70 years, starting with the paper of Gussow in 1954 and Silverman in 1965, going through the experimental and field studies of Thompson in the late '70s and '80s, as well as a number of other geochemists publishing papers in the '90s and 2000. Phase fractionation refers to the molecular partitioning of individual petroleum components to the vapor gas and liquid oil phase due to pressure reduction. Some of the terms that have been used to refer to these processes include separation migration by Silverman in 1965, evaporative fractionation used by Thompson, 1987, 2010, migration fractionation used by Dzou and Hughes, 1993 and Curiale and Bromley, 1996, gas washing used by Meulbroek et al., 1998 and Losh and Cathles, 2002 and 2010. Evaporative / migration fractionation is phase fractionation during tertiary migration, which is migration from one trap to another that could significantly affect fluid properties and/or volumes of petroleum accumulations. Evaporative fractionation also refers to the process of contacting an oil accumulation with excess methane and removing the equilibrated gas. Gas washing refers to fractionation processes caused by multiple events of gas mixing with oil and vapor phase exsolution. Phase fractionation refers to the molecular partitioning of individual petroleum components to the gas and oil phase due to pressure reduction. The cartoon illustrates the concept of evaporative or migration fractionation, which involves the physical separation of a gas phase from an existing saturated oil accumulation by leakage from a trap due to pressure reduction, for example, through fault re-activation or fractures, and subsequent vertical or lateral migration to a shallower trap where the gas may undergo retrograde condensation due to lower reservoir pressure and temperature and form a new gas condensate accumulation or mix with an existing oil or gas accumulation. Silverman, in 1965, reported a study where a gas cap of deeper accumulation bleeds-off along faults, leaving a residual oil accumulation with a 40 degree API gravity, depleted in light ends in the deeper reservoir, and a shallower gas condensate accumulation with oil gravity of 50 API. The end result is two genetically related accumulations but with very different fluid properties. The important point here is that oil geochemistry can detect the characteristics of a residual oil accumulation and recognize the effects of phase fractionation processes. This is a map illustrating the world locations with evaporative / migration fractionation occurrences based on publications in open literature. The map shows that this type of processes are not rare occurrences and might be widespread processes in the evolution of the basins, as suggested by Thompson, 2010. In conclusion, always involve an experienced geochemist in the planning of your exploration and appraisal drilling programs in order to ensure obtaining the value of reducing uncertainties and risks related to presence, size, and properties of hydrocarbon accumulations. Thank you very much for your attention. Feel free to give us feedback or ask questions.