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LGS Luncheon – March 2020


Exploration and Production High-Grading Utilizing Petroleum Geochemistry

Dan Jarvie, Wildcat Technologies/Worldwide Geochemistry/TCU Energy Institute


The present-day keys to petroleum source rocks is the knowledge of how much petroleum they have generated and expelled versus how much they have retained and the quality of each (API gravity, viscosity, sulfur content and GOR). The former describes the potential for petroleum in conventional reservoirs and the latter the amount retained in the source rock or hybrid system. A hybrid unconventional system is defined as juxtaposed organic-rich and organic-lean intervals. The producibility of petroleum is of course related to a variety of factors including many chemical and physical properties.

Quantitation of the potential amount of petroleum generated by a source rock is a relatively simple process of converting the organic carbon and hydrogen potential of a source rock to petroleum. Most marine source rocks have petroleum generation potentials of 30-60% of their original kerogen carbon and carbon-linked hydrogen content. The key is consideration of both carbon and hydrogen contents. A source rock of 1.00 wt.% with a relative hydrogen content as measured by hydrogen index of 600 mg petroleum potential per g TOC has only 50% convertibility to petroleum at complete conversion; at peak oil this would only be ca. 25% convertibility. Figure 1 shows the potential for petroleum in boe/af with full conversion of a 1% rock with varying levels of hydrogen. Any other TOC or HI value can be extrapolated between values. Of course, most source rocks at not fully converted and so values in the oil window are lower. While thickness increases the total potential of petroleum generation of an organic-lean rock (< 1% TOC), it does not change the amount of petroleum per acre-ft nor its expulsion efficiency, i.e., an insufficient or poor source rock is not made ‘good’ by increasing thickness.


Figure 1. Petroleum generation potential per foot for a 1% TOC rock at varying hydrogen contents. Assumes full conversion of organic matter.

Expulsion occurs as a general function of carbon and hydrogen content, i.e., the higher the hydrogen index, the higher the expulsion (the higher the oil saturation). While TOC is an important generation component, it also serves as a retention component due to sorption of petroleum by organics. The amount of petroleum expelled and the opposite, retained, becomes of importance for conventional systems (the former) and unconventional, the latter.

Measurement of oil in a source rock are limited by loss of petroleum during sample retrieval, handling, storage, and processing. Regardless of whether samples are frozen or follow strict preservation processes, there is always loss of petroleum. However, this petroleum loss may be restored by further analysis of the oil. Fingerprinting allows the ‘lost’ petroleum, both gas and oil, to be restored. This process allows the laboratory measured oil in the reservoir to be restored and the amount generated to be calculated, thereby allowing assessment of both in situ and expelled petroleum contents. If the composition of the petroleum (density) and porosity are ascertained, oil saturation may be computed from these data on source rocks. Oil evaporation is a function of its volatility, permeability, oil type, TOC, pressure, and mineralogy among various factors.

One issue with mapping petroleum maturity windows is that the product type and quality is time dependent. Source rocks may expel oil at multiple but varying levels of thermal maturity ranging from heavy oil, black oil, volatile (light) oil, condensate, and gas. Thus, the source rock maturity may not reveal what is found in a conventional reservoir. Even in source rock reservoirs, production often does not reflect what actually is in the reservoir (source) rock. This is the result of fractionation, which occurs whenever petroleum moves (except dry gas). This is particularly true in the early to middle oil window as oil has large polar molecules (resins and asphaltenes) that readily sorb to organics as well as inorganics (thereby affecting wettability). For example, in parts of the Midland portion of the Permian basin, Wolfcamp source rocks are early mature to peak oil window. The in situ oil is comprised of a full range of petroleum molecules both hydrocarbon and polar resins and asphaltenes) While production yields a high quality oil for an amount of time, the presence of heavy polar petroleum in the source rock will eventually occlude the pore throats in tight rock resulting in increased gas production.

Restricting discussion to marine source rocks only, marine carbonates and marine shales generate petroleum of varying composition at varying temperature especially the earliest onset of generation. Carbonates generate at lower temperature, but their composition is dominated by the polar constituents, which are not as valuable, do not produce as well, and tend to occlude pore throats. Difference in source rock types related to their mineralogies and related sorptive affinities also impact producibility.

In unconventional tight oil systems, the optimum production occurs in the volatile (light) oil window, which is about 0.95 to 1.15%Ro (vitrinite reflectance or equivalent). However, that said, other processes often affect reservoir properties ranging from secondary charges, gas exsolution, or other alteration processes.

Finally, a very important part of geochemistry is assessing production for compartmentalization and mixing, if any, of stimulated zones both or all containing oil. Initial results may be considerably different from production through time; thus, collecting samples monthly is a good approach whether the samples are analyzed or not.

Data and analysis of the Wolfcamp, Bone Spring, Eagle Ford, Tuscaloosa, Smackover, and U. Jurassic Deep Water GOM source rocks are utilized to illustrate these various points.


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Daniel M. Jarvie
Consultant in Organic Geochemistry
PO Box 789 Humble, Texas 77347
218 Higgins Street Humble, Texas 77338

Dan Jarvie is an analytical and interpretive organic geochemist. He has studied or been involved in evaluation of conventional petroleum systems around the world but is most noted for his ongoing work in unconventional shale-gas exploration particularly the Barnett Shale of the Fort Worth Basin, Texas. His specialties include source rock characterization for tight oil resource assessments, but also detailed source rock characterization for conventional petroleum systems analysis including bulk and compositional kinetic determinations, high resolution light hydrocarbon and fingerprinting analysis, and pyrolysis studies.

He founded Humble Instruments and Humble Geochemical Services in 1987, which were sold to Weatherford International in 2007. He also worked as a Visiting Scientist at Institut Francais du Petrole (IFP) and was Chief Geochemist for EOG Resources. Dan now works as a consultant to industry.

Mr. Jarvie was in the U.S. Navy prior to earning a B.S. from the University of Notre Dame. He was mentored in geochemistry by Wallace Dow and Don Baker of Rice University and has published 60+ papers in peer-reviewed scientific journals. He is a member of American Association of Petroleum Geologists, Rocky Mountain Association of Geologists, West Texas Geological Society, American Chemical Society-Geochemistry Division, Society of Petroleum Engineers, The Society for Organic Petrology, and European Association of Organic Geochemists.

Recent Publications


Jarvie, D.M., D. Prose, B.M. Jarvie, R. Drozd, and A. Maende, 2017, Conventional and unconventional petroleum systems of the Delaware basin, Search & Discovery Article #10949, 21 p.

Jarvie, D.M., 2017a, Perspectives on shale resource plays, in Geology: Current and Future Developments, Vol. 1, eds., Isabel Suárez-Ruiz and João Graciano Mendonça Filho, pp. 316-343.

Jarvie, D.M., 2017b, The interaction of organic and inorganic matter: Impact on composition and fractionation of petroleum, 2017 HGS Mudstone Conference, Integrated Approaches of Unconventional Reservoir Assessment and Optimization, 16 p.

Jarvie, D.M. and A. Maende, 2016, Mexico’s Tithonian Pimienta Shale: Potential for unconventional production, URTeC paper #2433439, 15p.

Jarvie, D.M., 2015, Geochemical assessment of unconventional shale gas resource systems, in Fundamentals of Gas Shale Reservoirs, 1st edition, R. Rezae, ed., John Wiley & Sons, Inc., pp. 47-69.

Jarvie, Daniel M., 2012a, Shale resource systems for oil and gas: Part 2 – Shale oil resource systems, in J. Breyer, ed., Shale reservoirs – Giant resources for the 21st century, AAPG Memoir 97, pp. 1-31.

Jarvie, Daniel M., 2012b, Shale resource systems for oil and gas: Part 1 – Shale-gas resource systems, in J. A. Breyer, ed., Shale reservoirs – Giant resources for the 21st century: AAPG Memoir 97, p. 69-87.

Jarvie, Daniel M., Robert J. Coskey, Michael S. Johnson, and Jay E. Leonard, 2011, The Geology and Geochemistry of the Parshall Field Area, Mountrail County, North Dakota in RMAG’s The Bakken-Three Forks Petroleum System in the Williston Basin, eds. John W. Robinson, Julie A. LeFever, and Stephanie B. Gaswirth, pp. 229-281.

Loucks, R.G., R.M. Reed, S.C. Ruppel, and D.M. Jarvie, 2009, Morphology, Distribution and Genesis of Nanometer-Scale Pores in the Mississippian Barnett Shale, Journal Sed. Res., v. 79, pp. 848-861.

He earned his PhD from the University of New Mexico in 1980; his M.S. in geology from the same university in 1977; and his B.S. in geology from the New Mexico Institute of Mining and Technology in 1973. He is a Certified Petroleum Geologist.

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