- Let's look now at some examples of Geochemistry interpretations that I used to evaluate the primary and secondary processes controlling fluid properties. Let's start with gastro chemistry, but first let's remind ourselves, what are Carbon isotopes and why gas Carbon isotopes can be used as maturity indicators of the source rock that generated hydrocarbons. Isotopes are variants of the same chemical element with the same number of protons and different number of neutrons. There are three naturally occurring isotopes of Carbon, Carbon 12, Carbon 13 and Carbon 14. Carbon 12 and Carbon 13 are the stable isotopes and they occur in proportion of approximately 99 to one. So, Carbon 12 is much more abundant isotope. Quantities of different isotopes are measured by mass spectrometry and compared to a standard, the established reference material is PeeDee Belemnite or PDB, which is a Cretaceous marine fossil from PeeDee formation in South Carolina. The Carbon isotope ratio for this material is accepted to be Zero. The Carbon isotope ratio for material is calculated using the formula shown here. And the units that are used are parts per thousand or per mil. Let's understand now the reasons, why gas carbon isotopes can be used as gas maturity indicators? The fact is that bond energy of Carbon 13 bonds is slightly higher than the bond energy of Carbon 12 bonds. This means that it takes more energy to break Carbon 13 bonds compared to Carbon 12 bonds. With increasing maturity, which is function of temperature and time, the kerogen, which is the insoluble organic material in the source rock starts to break down and generates oil and gas. With the Carbon 12 bonds breaking preferentially earlier or at lower maturity. As a result, the Carbon isotope ratio for gas components becomes heavier or enriched in Carbon 13, with increasing maturity. Here is an example of application of gas isotopes of Ethane and Propane to evaluate gases collected from different parts of the same basin. The figure presents the Ethane Carbon isotope ratio on the x axis and the Propane Carbon isotope ratio on the y axis. In accordance with what we discussed in the previous slide, the maturity of both gas components increases from lighter to heavier isotope ranges. Plotted gas isotope data illustrate a clear maturity trend. The data are from different areas of the same basin and show a significant range in gas maturity across the basin. Ethane values vary from minus 36 to minus 24 per mil, and Propane values vary from minus 42 low maturity, to minus 26 high maturity, per mil. The analytical error for this set of Carbon isotope data is plus, minus 0.3 per mil. Here is an example of another gas interpretation plot that uses both gas composition as the ratio of Methane to the sum of Ethane and Propane on y axis and Carbon isotope ratio of Methane on the x axis. The figure presents one of many plots that have been developed by geochemists during the last 50 years to evaluate source rock type and maturity from gas geochemistry. This one is from Whiticar. The plot utilizes both gas molecular composition, the ratio of Methane to the sum of Ethane and Propane and Carbon isotopes of Methane. The end member bacterial gas consists mainly of Methane and has very light Carbon isotope ratio. Minus 70 to minus 80 per mil. The thermogenic gas has isotopically much heavier methane, heavier than minus 50 per mil and has a higher concentration of Ethane and Propane. Mixing of bacterial and thermogenic gases could be identified within lines A and B. Thermogenic gas generated from coal or terrigeneous, type three organic matter could be differentiated from gas generated from marine, type two kerogen in the source rock. Source rock and maturity indicators could be evaluated from the composition of oils as well. The figure presents typical oil gas chromatogram or GC. Increasing time, temperature of GC analysis on the x axis and detector response or component abundance on the y axis. Typical oil gas chromatogram is dominated by straight chain n alkane or paraffin compounds with different carbon numbers. Indicated on the chromatogram are n alkanes with n 20 and 30 carbon numbers. Source rock type and maturity oil indicators are present in different carbon number ranges, gasoline, mid range, biomarkers and in addition to n alkanes, include many other types of compounds branched, cyclic, aromatic hydrocarbons, which are in small abundances compared to the n alkanes and are buried in the baseline of the GC. Here is an example of utilizing the gasoline range of compounds for fluid maturity classification based on the work of Thompson, 1993. The table shows the oil maturity classification based on two parameters, Heptane and Isoheptane values. Heptane and Isoheptane values are ratios of different compounds in the gasoline C seven range, proposed to be utilized for maturity classification of petroleum by Thompson, based on study of 76 oils from different producing basins in the United States. The data presented in the plot are from different formations of the same basin. The oils plotting as Supermature are from deeper formations with much higher maturity compared to the producing formations of the oils falling in the mature and normal oil fields, which is geologically consistent with the proposed classification. This is an example plot to interpret and classify source rock Lithologies and Depositional environments using oil parameters proposed by Hughes, Dzou, 1989 and Dzou and Hughes 1993. The plotutilizes a ratio of two isoprenoid compounds, Pristane and Phytane on the x axis and a ratio of two aromatic compounds, a sulfur containing Dibenzothiophene and Phenanthrene on the y axis. The data plotted illustrate a clear distinction between the blue data with higher Dibenzothiophene, Phenanthrene and lower Pristane, Phytane ratio, which suggest origin from carbonate dominated source rocks deposited in marine environment, and the other data points which suggest origin from marine clastic, shale source rocks.