Leigh C. Price

Thermal stability of hydrocarbons in nature: Limits, evidence, characteristics, and possible controls

Numerous petroleum-geochemical analyses of deeply buried, high-rank, fine-grained rocks from ultra-deep wellbores by different investigators demonstrate that C15+ hydrocarbons (HCs) persist in moderate to high concentrations at vitrinite reflectance (R0) values of 2.0–5.0% and persist in measurable concentrations up to R0 = 7.0–8.0%, at which point the thermal deadline for C15+ HCs 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: C15+ HCs begin thermal cracking at R0 values of 0.9% and are completely thermally destroyed by R0 = 1.35%; C2-C4 HC gases are thermally destroyed by R0 = 2.0% and methane is thermally destroyed by R0 = 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 C15+ HC concentrations in some fine-grained rocks at ranks of R0 ≥ 0.9%. The fact that observed data (C15+ HCs thermally stable to R0 = 7.0–8.0%) is so far removed from predicted behavior (C15+) HCs expected to be thermally destroyed by R0 = 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 C15+ HC concentrations in fine-grained rocks with Type III OM over R0 = 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 C15+ 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 C15+ HC generation, flushing oil (including C2–C4 HC gases condensed into the liquid phase) out of deep basinal traps by Gussows (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.

The influence of pressure on petroleum generation and maturation as suggested by aqueous pyrolysis

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 C1 to C4 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 C15+ hydrocarbons in fine-grained rocks even to ultra-high maturation ranks.

Solubility of crude oil in methane as a function of pressure and temperature

The solubility of a 44° API (0.806 sp. gr.) whole crude oil has been measured in methane with water present at temperatures of 50 to 250°C and pressures of 740 to 14,852 psi, as have the solubilities of two high molecular weight petroleum distillation fractions at temperatures of 50 to 250°C and pressures of 4482 to 25,266 psi. Both increases in pressure and temperature increase the solubility of crude oil and petroleum distillation fractions in methane, the effect of pressure being greater than that of temperature. Unexpectedly high solubility levels (0.5–1.5 grams of oil per liter of methane—at laboratory temperature and pressure) were measured at moderate conditions (50–200°C and 5076–14504 psi). Similar results were found for the petroleum distillation fractions, one of which was the highest molecular weight material of petroleum (material boiling above 266°C at 6 microns pressure). Unexpectedly mild conditions (100°C and 15,200 psi; 200°C and 7513 psi) resulted in cosolubility of crude oil and methane. Under these conditions, samples of the gas-rich phase gave solubility values of 4 to 5 g/l, or greater. Qualitative analyses of the crude-oil solute samples showed that at low pressure and temperature equilibration conditions, the solute condensate would be enriched in C5–C15 range hydrocarbons and in saturated hydrocarbons in the C15+ fraction. With increases in temperature and especially pressure, these tendencies were reversed, and the solute condensate became identical to the starting crude oil. The data of this study, compared to that of previous studies, shows that methane, with water present, has a much greater carrying capacity for crude oil than in dry systems. The presence of water also drastically lowers the temperature and pressure conditions required for cosolubility. The data of this and/or previous studies demonstrate that the addition of carbon dioxide, ethane, propane, or butane to methane also has a strong positive effect on crude oil solubility, as does the presence of fine grained rocks. The n-paraffin distributions (as well as the overall composition) of the solute condensates are controlled by the temperature and pressure of solution and exsolution, as well as by the composition of the original starting material. It appears quite possible that primary migration by gaseous solution could ‘strip’ a source rock of crude-oil like components leaving behind a bitumen totally unlike the migrated crude oil. The data of this study demonstrate previous criticisms of primary petroleum migration by gas solution are invalid; that primary migration by gaseous solution cannot occur because methane cannot dissolve sufficient volumes of crude oil or cannot dissolve the highest molecular weight components of petroleum (tars and asphaltenes).

Organic geochemistry of the 9.6 km Bertha Rogers No. 1. well, Oklahoma

Abstract Organic geochemical analyses of fine-grained rocks from the 9.590 km Bertha Rogers No. 1 well have been carried out: total organic carbon, Soxhlet extraction and silica gel chromatography, C15+ saturated and aromatic hydrocarbon gas chromatography and mass spectrometry, pyrolysis, kerogen analysis, X-ray diffraction and visual kerogen analysis. Rocks ranged in age from Permian to Ordovician; the well has an estimated bottom hole temperature of 225°C. Some data from this study are inconsistent with conventional theories concerning the generation and thermal destruction of hydrocarbons. For example, appreciable amounts of C15+ gas-condensate-like hydrocarbons are present in very old rocks currently at temperatures where current theory predicts that only methane and graphite should remain. Also, substantial amounts of pyrolyzable C15+ hydrocarbons remain on the kerogen in these deeply buried Paleozoic rocks. This suggests, at least in somes cases, that temperatures much higher than those predicted by current theory are required for generation and thermal destruction of hydrocarbons. The data from this well also suggest that original composition of organic matter and environment of deposition may have a much stronger influence on the organic geochemical characteristics of fine-grained sediments than has previously been ascribed to them. The results from this well, from other deep hot wells in which temperatures exceed 200°C, and from laboratory experiments, suggest that some of the basic concepts of the generation and maturation of petroleum hydrocarbons may be in error and perhaps should be reexamined.

Organic geochemistry of core samples from an ultradeep hot well (300°C, 7 km)

South Texas cores of Lower Cretaceous rocks from a depth of 6400.8 to 7544.6 m at present-day temperatures of 262–296°C have high concentrations of C15+ hydrocarbons. Bitumen coefficients range from 105 to 367 mg/g and C15+ extractable bitumen ranges from 500 to 2200 ppm. Some generation potential remains associated with the kerogen of these rocks. In addition to exhibiting the above organic-geochemical properties, characteristic of the zone of intense hydrocarbon generation, these rocks also have organic-geochemical properties, attributed to the zone of hydrocarbon extinction or greenschist metamorphism. These characteristics are: high vitrinite reflectance (R0) values, 4.4–4.8; low H/C ratios, 0.30–0.58; high saturate/aromatic hydrocarbon ratios, 7.05–20.6; high hydrocarbon/NSO ratios, 2.65–4.66; and high transformation index ratios [S1(S1 + S2)], 0.61–0.87. The data from this (and other wells we have studied) show that high concentrations of C15+ hydrocarbons are thermally stable to high temperatures (at least 300°C) in abnormally-pressured semi-closed systems over geologic time. Concepts prevelant among petroleum organic geochemists concerning the thermal fate of hydrocarbons, with subsequent graphite formation, and greenschist metamorphism, are in sharp contradiction to these data. Conventional concepts of the distribution of heavy hydrocarbons with increasing temperature and depth apparently require further review and revision.

Evidence and characteristics of hydrolytic disproportionation of organic matter during metasomatic processes

Abstract 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 δ13C 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 ubiquitous 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 disproportionation 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.

Crude oil degradation as an explanation of the depth rule

Abstract 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.

Origins, characteristics, controls, and economic viabilities of deep- basin gas resources

Abstract Dry-gas deposits (methane ≥ 95% of the hydrocarbon (HC) gases) are thought to originate from in-reservoir thermal cracking of oil and C 2+ HC gases to methane. However, because methanes from Anadarko Basin dry-gas deposits do not carry the isotopic signature characteristic of C 15+ 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 C 15+ HCs. Other gas-composition data from both nature and laboratory experiments also suggest that most methane in dry-gas deposits originates from a post-expulsion fractionation of wet gases generated with C 15+ HCs into methane-rich deposits. 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 C 15+ HCs), very large, previously unrecognized, unconventional, deep-basin gas resources are expected. Nonetheless, economic recovery of these gas resources will depend on drilling, completion, stimulation, production, and maintenance procedures applicable to the unique characteristics of each unconventional gas-resource base. Isotopic values of methanes from nature and laboratory experiments suggest that most ‘thermogenic’ methanes with δ 13 C values of −50 to −45 may have a significant component of biogenic methane. Also, laboratory experiments demonstrate that organic-matter facies variations have as strong a control on HC gas chemical and isotopic values as maturity. Thus, estimation of gas maturities by gas isotopic or chemical characteristics can be misleading.

Time as Factor in Organic Metamorphism and Use of Vitrinite Reflectance as an Absolute Paleogeothermometer: ABSTRACT

The only evidence that time is a factor in organic metamorphism lies in the works of Karweil, Lopatin, and Connan. All three attributed the high degree of organic diagenesis in geologically older areas to todays presently low geothermal gradients End_Page 619------------------------------ and long burial (cooking) times. Yet the heat flows in all areas had been much higher in the geologic past due to volcanism, igneous intrusion, orogeny, metamorphism, and/or uplift and erosion. Mean random vitrinite reflectance (Ro) is an indicator of organic metamorphism. A plot of Ro versus present temperature from a number of areas that have not undergone major geologic mutilation, increases in tight (R = 0.97) linear fashion. Yet burial times for these different areas range from 0.3 to 240 m.y. These same data, when plotted against increasing burial time at constant temperature, do not show the expected trend of increasing Ro values with increasing burial time. Vitrinite reflectance data from a geothermal (rift valley) area with a maximum heating age of 10,000 years, directly overlie the preceding plot, which suggests the time needed for full organic maturation is 10,000 to 300,000 years, a geologic instant. Geochemical data from deep (up to 9 km), high-temperature (up to 300°C) wells having long burial times (up to 240 m.y.), suggest that some geochemical postulates are in error and that time has little effect on organic maturation. It appears that vitrinite reflectance can be used as an absolute paleogeothermometer from 20° to at least 400 + 20°C. End_of_Article - Last_Page 620------------

Organic Geochemistry and Petroleum Exploration--Problems?: ABSTRACT

Results of organic-geochemical studies of deep well bores contradict current concepts on the generation, maturation, and thermal destruction of hydrocarbons. Main-phase hydrocarbon generation (high bitumen coefficients) apparently occurs between 190 and 250°C in Lower Cretaceous to Devonian rocks in five separate well bores. In these same rocks, the kerogen still retains high values of pyrolyzable hydrocarbons normalized to organic carbon. All five well bores have had higher than 250°C paleotemperatures. These results indicate that much higher temperatures than those commonly accepted are required for the complete generation and thermal destruction of hydrocarbons. Other results from these studies contradict the following accepted organic-geochemical trends vers s depth: (1) maturation of saturated hydrocarbons; (2) the S1/S1 + S2 ratio (S1 = extractable bitumens and S2 = pyrolyzable hydrocarbons per thermal analysis); (3) the temperature at the maximum of the S2 peak; (4) the thermal phaseout of C15 + hydrocarbons; and (5) correlation of elemental kerogen composition and vitrinite reflectance with extractable and pyrolyzable hydrocarbons. Laboratory duplication of generation-maturation reactions in closed, pressurized, water-wet systems shows that the controlling parameters of these reactions are not as described in the accepted mathematical formulas modeling these reactions. Concepts concerning the generation and thermal destruction of hydrocarbons apparently have bee greatly oversimplified. End_of_Article - Last_Page 1363------------