Geology topics
Publications and source records attributed to L.C. Price.
The present author defends his conclusions. Two errors in his earlier paper (M.A. 84M/1107) are corrected. (Preceding abstract) -P.Br.
Detailed organic geochemistry has been performed on a large number of Lower Mississippian-Upper Devonian Bakken shales from the North Dakota portion of the Williston Basin, and 28 oils mainly from Mississippian Madison Group rocks from different basinal areas. Here we report results of Rock-Eval pyrolysis and vitrinite reflectance ( R o ) analyses. Variable paleoheat flows in the Williston Basin caused the threshold of intense hydrocarbon generation to occur at different depths in different basinal areas. In higher paleogeothermal gradient basinal areas, this event occurred at depths of 7,650-8,000 ft, and at 10,000 ft or deeper in lower paleogeothermal gradient areas of the Basin. Distinct organic metamorphic imprints in Williston Basin sediments were also caused by extreme, but variable, paleoheat flows in the basin, as well as secondary migration of crude oils from deep basinal source areas. The high paleoheat flows are postulated as being due to a Late Cretaceous - Paleocene aborted rift event. Only a small volume of Bakken shales in restricted areas of the Williston Basin was responsible for the oil found reservoired in Mississippian Madison Group rocks. However, this small shale volume has been responsible for a relatively large amount of crude oil. R o profiles in the Tertiary through Middle Jurassic rocks in the Williston Basin had steep, linear R o versus depth gradients, with strong reversals of R o values occurring in the Lower Jurassic rocks. The lower Mesozoic through Paleozoic rocks of the Basin had strongly suppressed R o values compared to the values in the Tertiary through Middle Jurassic rocks. This was especially true of the R o values in the Bakken shales. This R o suppression was due to a change in organic matter (OM) type from oxygen-rich terrestrially derived OM in the younger rocks, to a hydrogen-rich marine derived OM in the deeper, older rocks. The threshold of intense oil generation (TIHG) occurred in the Bakken shales of the Williston Basin at R o values somewhere between 0.9 and 1.7% (best estimate 0.9), as would be read in oxygen-rich OM. Much higher burial temperatures (and consequently R o values) than usually held to be necessary were required for both the TIHG as well as mainstage hydrocarbon generation in the Bakken shales. These results are most likely applicable in general to source rocks with hydrogen-rich OM. The data of this study have major implications to petroleum exploration as well as to petroleum resource assessment.
[No abstract available]
Petroleum-geochemical analyses of carbonaceous regionally metamorphosed rocks, carbonaceous rocks from ore deposits, and alkalic plutonic rocks from diverse settings, demonstrated the presence of very low to moderately low concentrations of solvent-extractable organic matter, this observation in spite of the fact that some of these rocks were exposed to extremely high metamorphic temperatures. Biomarker and ??13C analyses established that the extractable organic matter originated as sedimentary-derived hydrocarbons. However, the chemistry of the extractable bitumen has been fundamentally transformed from that found in sediment bitumen and oils. Asphaltenes and resins, as defined in the normal petroleum-geochemical sense, are completely missing. The principal aromatic hydrocarbons present in oils and sediment bitumens (especially the methylated naphthalenes) are either in highly reduced concentrations or are missing altogether, Instead, aromatic hydrocarbons typical of sediment bitumens and oils are very minor, and a number of unidentified compounds and oxygen-bearing compounds are dominant. Relatively high concentrations of alkylated benzenes are typical. The polar "resin" fraction, eluted during column chromatography, is the principal compound group, by weight, being composed of six to eight dominant peaks present in all samples, despite the great geologic diversity of the samples. These, and other, observations suggest that a strong drive towards equilibrium exists in the "bitumen." Gas chromatograms of the saturated hydrocarbons commonly have a pronounced hump in both the n-paraffins and naphthenes, centered near the C19 to C26 carbon numbers, and a ubiquitos minimum in the n-paraffin distribution near n-C12 to n-C14. Multiple considerations dictate that the bitumen in the samples is indigenous and did not originate from either surficial field contamination or from laboratory procedures. Our observations are consistent with the hydrolytic disproportion of organic matter (HDOM), in which water and organic matter, including hydrocarbons, easily exchange hydrogen or oxygen with one another under certain conditions (Helgeson et al., 1993). The process appears to take place via well-known organic-chemical redox reaction pathways and is most evident in open-fluid systems. The conclusion that HDOM took place in the analyzed samples, thus producing the chemistry of the extractable bitumen, is supported by numerous previously published organic-geochemical studies of metamorphic, volcanic, plutonic, and ore-deposit-related rocks by other investigators. HDOM is suggested as an unrecognized geologic agent of fundamental importance. The process appears to control major chemical reactions in diverse geologic environments including, but not limited to, petroleum geology and geochemistry, regional metamorphism, and base- and precious-metal ore deposition. Copyright ?? 2001 Elsevier Science Ltd.
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Research studies based on foreland basins (mainly in eastern Colorado) examined three surface geochemical exploration (SGE) methods as possible hydrocarbon (HC) exploration techniques. The first method, microbial soil surveying, has high potential as an exploration tool, especially hi development and enhanced recovery operations. Integrative adsorption, the second technique, is not effective as a quantitative SGE method because water, carbon dioxide, nitrous oxide, unsaturated hydrocarbons, and organic compounds are collected by the adsorbent (activated charcoal) much more strongly than covalently bonded microseeping Q-Cs thermogenic HCs. Qualitative comparisons (pattern recognition) of C8+ mass spectra cannot gauge HC gas microseepage that involves only the Q-Cs HCs. The third method, soil cakite surveying, also has no potential as an exploration tool. Soil calcite concentrations had patterns with pronounced areal contrasts, but these patterns had no geometric relationship to surface traces of established or potential production, that is, the patterns were random. Microscopic examination of thousands of soils revealed that soil calcite was an uncrystallized caliche coating soil particles. During its precipitation, caliche captures or occludes any gases, elements, or compounds in its immediate vicinity. Thus, increased signal intensity of some SGE methods should depend on increasing soil calcite concentrations. Analyses substantiate this hypothesis. Because soil calcite has no utility as a surface exploration tool, any surface method that depends on soil calcite has a diminished utility as an SGE tool. Isotopic analyses of soil calcites revealed carbonate carbon ??13C values of -4.0 to +2.07co (indicating a strong influence of atmospheric CO2) as opposed to expected values of-45 to -30%c if the carbonate carbon had originated from microbial oxidation of microseeping HC gases. These analyses confirm a surface origin for this soil calcite (caliche), which is not necessarily related to HC gas microseepage. This previously unappreciated pivotal role of caliche is hypothesized to contribute significantly to the poor and inconsistent results of some SGE methods.
It is widely accepted that natural gas is formed from thermal decomposition of both oil in reservoirs and, to a lesser extent, the organic matter in shales from which the oil was derived 1–6 . But laboratory pyrolysis experiments on shales do not reproduce the methane-rich composition typical of most gas reservoirs 7 , leading to suggestions 7 that other mechanisms, such as transition-metal catalysis, may be important. The discrepancy might, however, instead arise because gas (and oil) deposits have migrated from their source rocks, so that the reservoir composition might not be representative of the composition in the source rocks where the hydrocarbons were generated. To address this question, we have analysed gas samples coproduced with oils directly from a source rock (the Bakken shales, North Dakota, USA) where the local geology has prevented significant hydrocarbon migration. The methane contents of these Bakken-shale gases are much lower than that of conventional gas reservoirs, but are consistent with that from pyrolysis experiments 8,9 on these shales. Thus, because these Bakken gases form with (rather than from) oils, we argue that compositional differences between gases from source rocks and conventional gas deposits result from fractionation processes occurring after hydrocarbon expulsion from the source rock.
Dry-gas deposits (methane ???95% of the hydrocarbon (HC) gases) are thought to originate from in-reservoir thermal cracking of oil and C2+ HC gases to methane. However, because methanes from Anadarko Basin dry-gas deposits do not carry the isotopic signature characteristics of C15+ HC destruction, an origin of these methanes from this process is considered improbable. Instead, the isotopic signature of these methanes suggests that they were cogenerated with C15+ HC's. Only a limited resource of deep-basin gas deposits may be expected by the accepted model for the origin of dry-gas deposits because of a limited number of deep-basin oil deposits originally available to be thermally converted to dry gas. However, by the models of this paper (inefficient source-rock oil and gas expulsion, closed fluid systems in petroleum-basin depocenters, and most dry-gas methane cogenerated with C15+ HC's), very large, previously unrecognized, unconventional, deep-basin gas resources are expected. -from Author
Numerous petroleum-geochemical analyses of deeply buried, high-rank, fine-grained rocks from ultra-deep wellbores by different investigators demonstrate that C 15 + hydrocarbons (HCs) persist in moderate to high concentrations at vitrinite reflectance ( R 0 ) values of 2.0–5.0% and persist in measurable concentrations up to R 0 = 7.0–8.0%, at which point the thermal deadline for C 15 + HC's is finally approached. Qualitative analyses have been carried out on 1. (1) high-rank gas condensates which have been exposed to the HC-thermal-destructive phase, 2. (2) bitumens from high-temperature aqueous-pyrolysis experiments in the HC-thermal-destructive phase, and 3. (3) bitumens from high-rank, fine-grained rocks near the HC-thermal-destructive phase. These analyses clearly demonstrate that well-defined compositional suites are established in the saturated, aromatic, and sulfur-bearing aromatic HCs in and near the HC-thermal-destructive phase. On the other hand, accepted petroleum-geochemical paradigms place rigid limits on HC thermal stability: C 15 + HCs begin thermal cracking at R 0 values of 0.9% and are completely thermally destroyed by R 0 = 1.35%; C 2 -C 4 HC gases are thermally destroyed by R 0 = 2.0% and methane is thermally destroyed by R 0 = 4.0%. Furthermore, published data and observations in many HC basins worldwide support these models; for example, 1. (1) sharp basinal zonations of gas and oil deposits vs. maturation rank in HC basins and 2. (2) decreasing C 15 + HC concentrations in some fine-grained rocks at ranks of R 0 ≥ 0.9%. The fact that observed data (C 15 + HCs thermally stable to R 0 = 7.0–8.0%) is so far removed from predicted behavior (C 15 + ) HCs expected to be thermally destroyed by R 0 = 1.35%) may be due to 1. (1) a lack of recognition of some important possible controlling parameters of organic matter (OM) metamorphism and too much importance given to other assumed controlling parameters; and 2. (2) assigning HC distribution patterns in petroleum basins to HC thermal cracking when such patterns may be due to other causes. In the first case, laboratory experiments strongly suggest that the presence of water, increasing fluid pressures, and closed systems (product retention) all suppress OM metamorphic reactions. Conversely, the absence of water, low fluid pressures, and open systems (product escape) all promote OM metamorphic reactions. These experiments also demonstrate that OM metamorphic reactions proceed by reaction kinetics greater than first order. Thus, the effect of geologic time appears to have been over-estimated in OM metamorphism. In the second case, the strong decreases in C 15 + HC concentrations in fine-grained rocks with Type III OM over R 0 = 0.9−1.35% are most probably due to intense primary migration and loss of HCs to drilling muds during the trip uphole in drilling operations. Data from coals demonstrate that these decreases in HC concentrations cannot be due to C 15 + HC thermal destruction. Oil deposits are generally found at shallow depths in basins, and “dry gas” (methane ≤ 98% of all HC gases) deposits are found at the greatest depths. This HC distribution pattern would be caused by methane, generated during the late stages of C 15 + HC generation, flushing oil (including C 2 –C 4 HC gases condensed into the liquid phase) out of deep basinal traps by Gussow's (1954) principle of differential entrapment. Hence, only “dry gas” deposits are left in the basin deeps. Oil emplacement processes in traps during expulsion and secondary migration could also contribute to the HC distribution pattern observed in petroleum basins.
In petroleum geochemistry, extractable hydrocarbons (HCs) in source rocks have typically been studied by grinding the rock to a fine powder (≤100 mesh) and then extracting the HCs from the rock with a solvent. This procedure carries the implicit assumption that the HCs are homogeneously distributed throughout the rock. However, sequential Soxhlet extractions of whole (unpowdered) source rocks have shown that progressive extracts from the same rock can be quite different and may not even correlate with each other. A crude oil-like material clearly has been fractionated from indigenous bitumen in these rocks, has moved to cracks and parting laminae in the rocks, is ready for expulsion from the rocks, and is thus most accessible to the first extracting solvents. This process, which we believe is largely due to HC gases and carbon dioxide generated over all maturation ranks in source rocks, carries petroleum geochemical implications of a fundamental nature for oil-source rock correlations and gives insight into primary migration mechanisms, origin of oil deposits, and use of maturity and organic-facies indices.
Because fluid pressures are transient in sedimentary basins over geologic time, the effect of increasing fluid pressure on organic-matter metamorphism is difficult to determine, and conflicting opinions exist concerning its influence. Properly-performed aqueous-pyrolysis experiments can closely simulate hydrocarbon generation and maturation in nature, and thus offer an excellent way to study the influence of pressure. Such experiments, carried out on the Retort Phosphatic Shale Member of the Lower Permian Phosphoria Formation (type II-S organic matter) at different constant temperatures, demonstrated that increasing pressure significantly retards all aspects of organic matter metamorphism, including hydrocarbon generation, maturation and thermal destruction. This conclusion results from detailed quantitative and qualitative analyses of all products from hydrocarbon generation, from the C 1 to C 4 hydrocarbon gases to the asphaltenes, and also from analyses of the reacted rocks. We have documented that our aqueous-pyrolysis experiments closely simulated natural hydrocarbon generation and maturation. Thus the data taken as a function of pressure have relevance to the influence of normal and abnormal fluid pressures as related to: 1) depths and temperatures of mainstage hydrocarbon generation; 2) the thermal destruction of deposits of gas or light oil, or their preservation to unexpectedly high maturation ranks; and 3) the persistence of measurable to moderate concentrations of C 15 + hydrocarbons in fine-grained rocks even to ultra-high maturation ranks.
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Previous studies of crude oil degradation by water washing and bacterial attack have documented the operation of these processes in many different petroleum basins of the world. Crude oil degradation substantially alters the chemical and physical makeup of a crude oil, changing a light paraffinic low-S "mature" crude to a heavy naphthenic or asphalt base, "immature appearing" high-S crude. Rough calculations carried out in the present study using experimentally determined solubility data of petroleum in water give insight into the possible magnitude of water washing and suggest that the process may be able to remove large amounts of petroleum in small divisions of geologic time. Plots of crude oil gravity vs. depth fail to show the expected correlation of increasing API gravity (decreasing specific gravity) with depth below 2.44 km (8000 ft.). Previous studies which have been carried out to document in-reservoir maturation have used crude oil gravity data shallower than 2.44 km (8000 ft.). The changes in crude oil composition as a function of depth which have been attributed to in-reservoir maturation over these shallower depths, are better explained by crude oil degradation. This study concludes that changes in crude oil composition that result from in-reservoir maturation are not evident from existing crude oil gravity data over the depth and temperature range previously supposed, and that the significant changes in crude oil gravity which are present over the shallow depth range are due to crude oil degradation. Thus the existence of significant quantities of petroleum should not necessarily be ruled out below an arbitrarily determined depth or temperature limit when the primary evidence for this is the change in crude oil gravity at shallow depths. ?? 1980.