HGS Northsiders' Luncheon - Geochemical Assessment and Characterization of Petroleum Source Rocks and Oils, and Petroleum Systems, Permian Basin, U.S.A.
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Social 11:15 AM, Luncheon 11:30 AM
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Speaker: Dan Jarvie
Company: Renaissance Oil
Geochemical Assessment and Characterization of Petroleum Source Rocks and Oils, and Petroleum Systems, Permian Basin, U.S.A.
The Permian basin is comprised of three major sub-basins, the Midland Basin, Central Basin Platform, and Delaware basin. These basins have many of the same source rocks with variation in organofacies and thermal maturity as well as geological histories. The principal source rocks are found in the Permian Leonardian and Wolfcampian, Mississippian, and Devonian intervals with additional secondary source intervals. The key source rocks are the Woodford, Barnett, Wolfcamp, Spraberry, and Bone Springs.
Jones and Smith (1965) described five different petroleum systems strictly using elemental analysis of oils and their relative contents of carbon, oxygen, nitrogen, and sulfur. In the 1970s Jack Williams of Amoco and Williston basin fame inferred nine different petroleum systems based on geochemical analysis of over 500 oils (Williams, 1977). Recently Zumberge and Curtis (2017) showed a statistical analysis of oils and condensates from the Delaware basin with the inferred source rock type. In all cases, many oils were placed in an unknown category either due to mixing, alteration or otherwise unknown sources. However, precise geochemical description of an effective source requires a correlation between source and oils, which has not yet been accomplished in the Permian Basin. We can describe most of these systems as probable or prospective, but not necessarily as effective since the correlation proof is absent.
Table 1. Gross description of source rocks, Permian basin. While these source rocks dominate petroleum generation in the Permian basin, there are various divisions in these units that are both primary and secondary sources of petroleum. Among these geological periods, there is a total of fifteen different units capable of sourcing petroleum.
Drawing on previous work by Smith and Jones, Williams, Jarvie et al., 2001, Hill et al., 2003, Jarvie, 2017, and Curtis and Zumberge (2017) various petroleum systems for the Permian basin are shown in Table 2.
Assessment of the stratigraphic sequence for prospective source rocks begins with TOC analysis to identify which rocks have the quantity of organic matter likely to generate commercial amounts of petroleum. Figure 1 lists various formations in the Permian basin with their average TOC values based on analysis of archived cuttings. Archived cuttings often tend to provide lower TOC and pyrolysis yields than fresh cuttings and core samples. This phenomenon is related to sample quality, i.e., mixing of organic-lean and source rock intervals, often predominantly fines, and oxidation from storage.
With the surge in unconventional tight oil exploration, extensive core is now available and provides upgraded sample data for specific horizons. Such high-quality data is important for restoring original TOC values and obtaining estimates of the original petroleum generation potentials for resource assessments. Restored TOC and petroleum generation potential for the Wolfcamp in the Delaware and Midland basins from core data are shown in Figures 2 a-b.
The composition of petroleum (bitumen) is one factor affecting producibility from tight oil reservoirs. The SARA composition (Saturates, Aromatics, Resins, Asphaltenes) affects flow particularly in black oil maturity tight oil systems. The resins and asphaltenes are viscous, high polarity constituents and will occlude pore throats by affecting wettability. This is exacerbated in reservoir rocks with higher adsorptive affinities especially at black oil window thermal maturity. Production SARA results are not necessarily indicative of in situ petroleum composition, which is the key for reservoir performance and well operating conditions. As the resins and asphaltenes crack with increasing thermal maturity, enhanced production occurs when these products are reduced. Thus, thermal maturity assessment becomes a critical measurement in determining petroleum quality and phase.
A key maturity assessment for economic value is the determination of the volatile oil window and the yield of petroleum liquids in the early gas window. Understanding the relationship of thermal maturity to oil cracking is a key factor in such assessments. Oil cracking is very commonly misstated in presentations, papers, and exploration discussions in that it is often cited to occur at very high levels of thermal maturity (>1.5%Ro); such statements are derived from cracking of saturated hydrocarbons, one constituent of petroleum. Petroleum (bitumen) is comprised of the aforementioned SARA constituents that have different, but overlapping cracking kinetics. Oil cracking begins virtually contemporaneously with its formation from kerogen. This is obvious from the improvement in oil API gravity with increasing oil window maturation that corresponds to a decrease in resins and an increase in saturated hydrocarbons.
Thermal maturity measurements by vitrinite reflectance in marine shales and carbonates present a challenge for organic petrographers. An alternative or complementary approach is the use of quantitative aromatic hydrocarbons such as shown by Hill et al. (2004) and Rocher et al. (2015). Such data is highly reproducible and provides data on both oils and rock extracts. Regardless of the correlation to vitrinite reflectance, the values must be related to product type and phase.
Interpretation of geochemical data stating that a given resource is in the oil or gas window is insufficient and needs to be refined to specific product windows (Fig. 3). The oil window is subdivided into black and volatile oil windows, whereas the gas window is subdivided into condensate-rich wet, lean wet, and dry gas windows. Thermal maturity, hydrocarbon calorific values and GOR provide guidelines into these windows.
Thermal maturity must necessarily be related to product type and phase. One such parameter that is important for assessing yields of liquid petroleum is gas-to-oil ratios (GOR). As it is desirable to assess this prior to extensive drilling and from available samples such as oil extracted from reservoir rocks, integration of thermal maturity with expected GOR is valuable exploration and development interpretation. A simple geochemical technique in such assessments is oil and solvent-extracted oil from reservoir rocks is high resolution gas chromatographic fingerprinting. This technique has been shown to provide an indication of producible oil API gravity even with the loss of a considerable portion of the light to intermediate range hydrocarbons due to evaporation (Holba et al., 2014).
Restoration of “lost” petroleum is derived from a gas chromatographic (GC) fingerprint of oil extracted from the reservoir rock and any native produced oils. Regardless of sample type, there is always lost petroleum due to evaporation unless a sample is taken and preserved under reservoir conditions (Fig. 4a). However, using a curve fitting approach such as Kissin (1987), Thompson (2002) or Holba et al. (2014) restoration of lost oil can be achieved by fitting unevaporated n-alkanes. Such a fit usually results a straight-line logarithmic fit on volatile oils and condensates, and with related fitting equation (Fig. 4b), petroleum composition may be restored. This is applicable to volatile oil and condensate wet-gas windows only. Such restoration allows correlation to production GOR, but provides an intrinsic GOR value that revealing in situ petroleum GOR. As GOR is a moving target, correlation requires initial or early production results to achieve this correlation, but appears to corroborate the GORs computed via the Mango and Jarvie (2001) technique.
A comparison of production results to compositional data comparable to PVT results allows correlation of gas-to-oil ratios (GOR) to production. This further allows pre-drill assessment of likely GORs from solvent extraction of rock samples.
Dan Jarvie has worked in organic geochemistry since 1982 in various positions in laboratories as well as in interpretation of data. While his early involvement was primarily in instrumentation and laboratory analyses, he has specialized in the assessment of unconventional shale resource system over the last two decades. He founded and was president of Humble Instruments and Humble Geochemical Services from 1987 to 2007, which were sold to Weatherford in 2007. Dan was Chief Geochemist at EOG Resources, Houston, Texas until April 2015. Currently, he is working the onshore Tampico-Misantla basin, Mexico for Renaissance Oil and has various pro bono research projects underway.
He was in the U.S. Navy from 1968-1974 and graduated from the University of Notre Dame in 1976. He was mentored in organic geochemistry by Wally Dow and Don Baker of Rice University. He is an adjunct professor at TCU and a member of the scientific board for TCU’s Energy Institute. His residence has been on top of the Humble Salt Dome since 1981.
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