Huge volumes of recoverable oil can originate and reside in the lower maturity (.65-.9 Roe?) oil window (and may be mid-30’s gravity).
If you have a similar background (and gray hair) to me, you have been scrambling for at least the last 15-20 years to learn everything you can about “Petroleum Geochemistry”…I actually commissioned my first service company geochemical study much earlier in 1986 and applied that data, but for much of my career I have generally worked in areas of “known” hydrocarbons. I realized very early that good mud log shows are qualitative indications of Rock-Eval “S1” (“free oil” or “free gas”; If you did not core with oil based mud). Recently, I have been lucky enough to be exposed to and also work with some world renowned and experienced geochemists (a few of my favorites are mentioned here) and to be exposed to a number of different geochemical service companies (in addition to many geochemical courses; I cut the first core in a newly developing source rock play and Weatherford performed a “Jarvie style” geochemical evaluation; I have been exposed to the biomarker work of John Zumberge; attended the excellent “cookbook” biomarker school of Harold Illich and John Curtis; and have heavily followed the Rock-Eval work of Dan Jarvie for a number of years and Dan has helped me with a number of personal communications). I have also been included as a Coauthor in a recent basinwide Petroleum Systems study.
I believe all of the “easy” Geochemical sourcerock plays (oil above “1 Roe/Vre”) are known (to someone) and have been found (perhaps not yet exploited). Just visualize the North America Shale Play maps that are scattered throughout the literature…and overlay a similar map on petroleum provinces around the world (where economics and world politics may be the main restraint and delay; maybe some outlying world plays also need substantial added documentation). For a number of years I have learned and read where geochemists focus upon having to have Ro (Roe, Vre…focus upon Tmax instead, you choose) of above “1.1 or 1.2” for “commercial” oil recovery (clearly cited as around 1 or above). It should be recognized by most that as you move higher in the oil window, you calculate higher reserves. Most recently a Geochemist quoted needing greater than “.9” for significant oil generation and recovery from his identified source rock in a new play. With reference to this “.9”, the geochemist did not realize that at no location in the basin or adjacent kitchens did depth of burial and associated Roe reach above .87, but one of the sourced conventional reservoirs (that he documented by name) has produced over 50,000,000 BO of 32-38 degree gravity oil, and source rock laterals are producing at monthly rates significantly above 12,000 BOPM.
In several basins, I have watched a number of active, niche, horizontal players that are clearly making “good wells” (and calculating and projecting “good” reserves) in plays, pursuing ranges of Roe from “.65 to .9” (such as portions of the Niobrara, Bakken, Wolfcamp...). For the petroleum industry, I see substantial added future value in heavily developed horizontal oil plays, as extensive areas which may have been bypassed due to someone’s poorly documented concerns about “1.0 Roe” or basins that have been ignored due to “1.0” (even when large volumes of conventional oil originating from those sources has been produced). How “low can you go” with maturation for economic hydrocarbons and reserves? Clearly not all organic types and potential plays will work, but some will, with low risk (if you understand the geochem and have the data). It seems obvious that huge volumes of recoverable hydrocarbons can originate and reside in this “lower” Roe range (not to mention that the prospective intervals are likely shallower, reducing the cost). For me, one of the main remaining problems for Geochemists and geochemical service companies relates to recognizing lower limits of maturation (Roe, Vre..lower maturation) as related to commercial oil recovery in sourcerock plays (or even recovery from conventional reservoirs in basins where economic Roe is poorly understood).
How can there be such variation between known hydrocarbons and expert opinions (not some weird migration problem or interformational migration) related to known source rocks and anticipated production from the source? I believe it is documented that in many cases around the edges of some stratigraphic source rock plays the oil produced from current “.7” rocks (.7 for example here) has actually migrated from “.8” rocks (apparent Roe value shifted higher about “.1”; reducing the maturation risk and providing a risk buffer if you are pursuing lower maturity oils). Other “buffers” increasing oil production at lower maturations relate to fractures in brittle rock and the recognition of organic porosity. For a number of reasons one of my favorite papers is Paul Devine’s (2014, Beyond TMAX…, reference at the end; sorry I have not actually met Paul). Here I have inserted a Devine style graph (figure a) from some of my work. Note the X axis plots Tmax instead of Roe (I located calculated Roe of .60 and .95 in red on the graph). Really,to focus upon onset maturation for various organic Types along the bottom of figure a (added as figure b), I have also scaled and inserted a “Conversion of Organic Matter” graph. Similar conversion graphs can be found from the industry, but this one is based upon a Dan Jarvie graph (from circa 2007). Note the difference in onset maturation temperatures for most recognized organic Types (I, II, II-S, and Type III) and the cartoonish relative volumes of transformed hydrocarbons indicated by color. I believe Devine’s immature line relates back to onset and early maturation variations. I have also overlain, as a reference, the general area of approximately 50% Transformation Ratio (TR) for “Type II” organic material, with early onset and Transformation Ratio being the key to resulting lower maturity oil volumes.
Several “Kerogen Conversion” or “Transformation Ratio” graphs plotted for a range of differing organic types have been known for a number of years (inserted here as figure c; Waples’ graph modified from his 1998 data). If you transform more organic material to hydrocarbons, what remains in its wake…more organic porosity, and if you transform more at lower onset temperatures, it seems like common sense that you should have more early onset organic porosity! This graph, figure c, demonstrates a substantial variation in conversion/transformation below and up to “.9 Roe”. Without getting off on a tangent, I believe the organic “Types” and organic facies as plotted related to Rock-Eval (and even with biomarkers) may be too broad brush when it comes to onset maturation and TR (transformation ratio), the key may be the specific macerals and organic species. It is well established that some macerals convert at higher rates and at different maturations. Organic facies should be just as variable as lithostratigraphic facies and one “Type” should not fit a basin or play. “If” the upper Devine graph (figure a) for a single core is actually for Type II-S sourced hydrocarbons, where would the 50% TR fall on the lower graph (figure b) and is there an inferred TR (significantly higher) for the plotted data?
From my ongoing questions to experts about the potential for oils below “1.0”, they are always quick to reference their concerns about asphaltenes, higher sulfur, nitrogen and other issues that can be associated with lower maturity oils and I am sure that has been a portion of their documented experience (and of course those concerns have to be evaluated). My specific knowledge is that .65-.9 can charge a conventional reservoir and produce over 50,000,000 barrels of mid 30’s gravity oil and I also defer to the number of very smart, successful people that have made a substantial niche in .65-.9 oil plays exploring for commercial oils (OK, but we still have to have commercial crude prices).
Perhaps the questions related to the need for Roe “1.0” (.9, 1.0, 1.1 1.2 etc.) for oil also relates to an understanding of the concept of “Peak Oil” which is posted on various conversion charts as it relates to maturation and/or generation. One reason I posted the Devine graph first, followed by the Waples graph, was to display the recognized variations in onset temperatures for known organic Types. As onset temperature varies, so follows a variation in “Peak Oil” for specific macerals, organic Type, and source rocks. Peak Oil is often marked on graphs by experts at around “1.1” (at peak oil of “1.1” on the Waples graph, the transformations ratios range from 17% to 94%!). In a specific source rock play, what is the knowledge of peak oil? “Peak oil” (from various geochemical approaches) may not be the same as Peak hydrocarbons! Who calibrated the data (production to peak oil Roe)? Where is the production and/or reserve data to document that Peak oil from pyrolysis is Peak hydrocarbons? For liquids we should be exploring and exploiting for Peak hydrocarbons! I have attached one of the best practical graph examples (figure d) that I have found from “Clarke et. al” where they graphed the Eagle Ford “18 Months Cum” liquids against Tmax (and I have added Roe calculations and red text) and you can see where the higher wells seem to plot around "1.12 Roe" (Tmax 460…ahhh “Peak oil” and Peak hydrocarbons for the EF), but the highest Cum well is at “.9”. Note the “onset” of their posted production at ".65", and most importantly note the sizeable area in the graph positioned within the “increasing oil volume” (area under “A”). No mention of Eagle Ford organic Type is included here.
As a Petroleum Geoscientist, one of the main goals in applying Rock-Eval and geochemistry should be the calculation and projection of valid reserves and identifying “sweet-spots” related to peak hydrocarbons. Most of the geochemical reserve methods revert back to some form of volumetrics, interpretation of “S1” from Rock-Eval, calculations of HIo (original hydrogen index), and or calculation from original TOC. If you have gone through those methods such as HIo and original TOC methods, they can be somewhat circular and fleeting…if you know original and current HI you can calculate TR and many refer to some immature analogue play or immature area (in a different depositional and organic facies, which is not right) to come up with an “original” value (immature Tmax should be fine). For me, (as an early numerical methods and curve fitting guy) Paul Devine’s graph is the first graphical method to actually project and pick HIo from the data, that I have found and it is very powerful! Here HIo projects to ~850 (and is confirmed from plots from multiple cores).
It would be great to have the financial backing and access to commercial production and geochemical data to review the correlation (between geochemical and Rock-Eval data to production) in a number of producing basins and source rock plays (which recognition would be key to reconnaissance and exploration in other plays/basins; maybe a major company has a version of similar work) and overlay Tmax/Roe with production (IP’s, GOR’s, cumulative and EUR’s) data.
A number of geochemical service companies have existing geochemical studies in their files and it would be relatively inexpensive to add a second economic phase to their studies, adding and relating the geochemical data to production maps, petroleum economics and peak hydrocarbons. Economic adds would take geochemical studies (perceived as esoteric in part by some key corporate individuals) and place an economic study in the hands of those financial managers that may be writing the checks and making the economic decisions. I have worked details in some specific source rock plays and public domain data in some others and I believe the overlay of valid Ro (Tmax etc.), TOC data and Rock-Eval contours with various limited production and hydrocarbon show maps and geologic maps (structure and source interval isopachs) have clearly allowed me to identify the early “sweet-spots” and minimize economic risks in every play. As Petroleum Geoscientists, I believe our only mandate is to cost effectively reduce the risk in efforts to find economic hydrocarbons.
I encourage every industry professional to go back and read Paul Devine’s paper, he discusses and presents details related to HI, TOC, S1, TR, NOC and a number of most important geochemical concepts. I can’t tell you how many schools, references, and how much work that I have had perform in my earlier efforts, to learn some geochemistry and to compile some of the materials set out in his paper.
References:
Devine, Paul. (2014). Beyond TMAX Thermal Maturity: Introducing an Original Method for Analyzing Source-Rock Pyrolysis Data to Predict Transformation Ratio and Retention Ratio in Resource-Play Evaluations. 10.15530/urtec-2014-1922839.
Clarke, P. R. et al. 2016. Assessing Well Performance in a Prolific Liquids-Rich Shale Play—An Eagle Ford…, AAPG Memoir 110, ed. Breyer J. A., Ch. 5, 213–240.
Waples, D. W. and Marzi, R. W., 1998. The universality of the relationship between vitrinite reflectance and transformation ratio. Organic Geochemistry, 28, 383-388.
With mention of basic geochemical learning and concepts (avoiding the complexities of biomarkers), I would be in remiss if I did not mention the numerous works of Dan Jarvie easily identified through Google. My favorite Jarvie exhibit that can help distinguish economic oil from immature oils and would contribute to this discussion is the “OSI” (oil saturation index) graph.
Good luck with your geochemistry!
Sincerely,
Joe A. Kast
Petroleum Consultant