Primary Migration Of Petroleum Research Articles

Unravelling the impact of lithofacies on the composition of NSO compounds in residual and expelled fluids of the Barnett, Niobrara and Posidonia formations

The influence of lithofacies on the composition of NSO (nitrogen-, sulfur- and oxygen- containing) compounds in unconventional petroleum systems has been investigated using examples of biogenic carbonate-rich Niobrara Shale, biogenic quartz-rich Barnett Shale and detrital clay-rich Posidonia Shale. The chosen sample sets all contain Type II marine kerogen in the peak–late oil window. Solvent extracts were analyzed using Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR-MS), combined with atmospheric pressure photoionization in positive ion mode ((+)-APPI) and electrospray ionization in negative ion mode ((−)-ESI). Covering source and reservoir units, our study furthermore enables tracing the impact of lithofacies on primary petroleum migration within the Niobrara and Barnett shales.Siliciclastic Barnett and Posidonia shale extracts reveal higher proportions of NSO compounds confirming their generally higher retention capacities for polar organic compounds. However, different retention specificities of biogenic quartz- and clay-rich rocks are indicated by varying NSO compound compositions in their bitumen fraction: biogenic quartz preferentially preserves and retains organonitrogen compounds, while the more polar acidic organooxygen species are preferably retained by clay minerals. Extracts from the carbonate rocks contain a larger fraction of nonaromatic cyclic sulfoxides and amides that are likely formed by oxidation processes during maturation of organic matter.Fractionations induced by the intra-formation migration differ between the Barnett and Niobrara sample sets. While low-polarity organonitrogen species are retained in both Barnett (to a greater extent) and Niobrara source units, a preferential migration of highly alkylated and small acidic NSO components out of the source is only observed in the Niobrara samples.

Fractionation of Pyrrolic Nitrogen Compounds Compounds during Primary Migration of Petroleum within the Barnett Shale Sequence of Marathon 1 Mesquite Well, Texas

The primary migration of petroleum has been recently described in detail for a thermally mature core of the Barnett Shale with almost nonvariant organofacies and maturity. Here, we use samples from the same well to provide new insights into the fractionation of pyrrolic nitrogen compounds during primary migration. Using gas chromatography–mass spectrometry (GC-MS), a decrease in concentration of carbazoles and benzocarbazoles was observed which correlated with migration distance. However, a preferential removal of individual isomers like benzocarbazole[a] relative to benzocarbazole[c] could not be detected. Enlarging the analytical window, we studied the effect of primary migration on high molecular weight nitrogen-containing compounds using Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR-MS) combined with electrospray ionization (ESI) in the negative ion mode. Compounds with one or two nitrogen atoms are most abundant. Among the N1 compounds, those with 12, 15, 18, 20, and 23 double b...

Effects of elastic anisotropy on primary petroleum migration through buoyancy-driven crack propagation

Material anisotropy may significantly influence the behavior of fluid transport in sedimentary basins and other environments with laminated or foliated rocks. In this paper, we present a fracture mechanics model to investigate primary migration of petroleum (oil and gas) through propagation of a vertical, buoyancy-driven blade crack in a transversely isotropic source rock. The source rock is assumed to have very low permeability and hence can be modeled as a linear elastic medium. Fracture parameters (stress intensity factor and crack opening displacement) are derived using an equivalent set of anisotropic elastic properties. The crack propagation velocity (i.e., petroleum migration velocity) and crack opening (fracture aperture) are determined using a fracture mechanics criterion together with the first order approximation of plane Poiseuille flow equations of fluid mechanics. For subhorizontal layering, we find that the fluid migration velocity and fracture aperture are significantly increased if the elastic modulus in the vertical direction is smaller than that in the horizontal direction. Finally, we discuss the applicability of the formula for isotropic materials along with the equivalent anisotropic elastic parameters introduced in this paper to evaluate fracture aperture for cracks in anisotropic rocks.

Control of facies, maturation and primary migration on biomarkers in the Barnett Shale sequence in the Marathon 1 Mesquite well, Texas

A great deal is known about the genetic relationships between biomarkers and their biogenic precursors in organic rich rocks. The same is true of the way in which biomarker compound ratios change during maturation. On the other hand, very little is known about whether a crude oil can fully retain its inherent compositional ancestry during expulsion from a source rock. Thanks to shales being characterized in great detail for their unconventional resource potential, new information is gradually coming to light. Here we report on observations in biomarker geochemistry of a thermally mature core of the Barnett Shale, in which organofacies and maturity are essentially the same, but where intraformational sources and reservoirs have already been reported.Our results indicate that most biomarkers are not fractionated as the primary migration of petroleum within source rocks takes place. The 20S/(20S + 20R) ratio of C27 steranes is uniform in the whole source-rock sequence, while the 20S/(20S + 20R) ratio of C29 steranes shows indistinctly high values in the reservoir unit. The 20S/(20S + 20R) ratio of diasteranes and the 22S/(22S + 22R) ratio of C31 17α-hopanes do not appear to have been fractionated, which may be a result of the thermal isomerization reactions predominating over and masking out the possible fractionation effects. Diasteranes/steranes ratios do not exhibit features that suggest an association with fractionation, but rather are broadly correlated with lithology. However, compared to the diasteranes/steranes ratios, the Ts/(Ts + Tm) ratio is much more sensitive to changes in mineral compositions. Variations in the Ts/(Ts + Tm) ratio show a positive correlation (R2 = 0.73) with mixed-layer illite-smectite content. Fractionation in the Ts/(Ts + Tm) ratio, if it has so occurred, may be subsequently overprinted by in-situ clay-catalyzed reactions.

CO2 storage in Residual Oil Zones: Field-scale modeling and assessment

Residual Oil Zones (ROZs) are formed as the result of secondary tectonic activities which trigger extensive oil remobilization after the primary petroleum migration. The ROZs are attractive targets for CO2 Enhanced Oil Recovery (CO2-EOR) and storage: first, because in many cases, the thickness of the ROZ ensures an overall recoverable volume of oil comparable to that of the Main Pay Zone (MPZ) and second, because the ROZ has favorable containment and capacity for large-scale and long-term EOR-storage projects. This study investigates one of the underlying theories of the ROZ formation, called the Altered Hydrodynamic Flow Fields (AHFF). The impact of the AHFF process on the formation of ROZs is specifically investigated using a field-scale simulation model for a Permian Basin San Andres reservoir. The simulation model is tuned and verified by validating the ROZ's characteristics, such as the thickness of the ROZ, the shape of the saturation profile, and the tilt of the OWC. The tuned Permian Basin San Andres reservoir model is used to simulate the primary recovery and the secondary waterflooding phases in the MPZ. Depending on the CO2 availability and ROZ development strategy, six different development scenarios are specified beyond the waterflooding phase. The corresponding simulations are performed to find the optimum EOR-storage strategies for the MPZ-ROZ through the extensive comparison of key performance parameters, including the cumulative oil recovery, CO2 storage and, net CO2 utilization. The results confirm the technical viability of CO2-EOR and storage in the ROZ. The most favorable expansion strategy in terms of oil production and CO2 storage is the simultaneous development of the MPZ and the ROZ from the beginning of EOR-storage process. Most importantly, the study demonstrates that the volume of the utilized CO2 has a substantial effect on the success of the EOR-storage. While other expansion strategies such as sequential development also provide reasonable oil production response and CO2 storage potential, early project expansion into the ROZ without sufficient investment in CO2 resources is shown to be detrimental to the economics of the project. Finally, several important technical considerations for CO2 storage are qualitatively discussed, including assessment of the ROZ storage capacity, saltwater disposal requirements, and reduced risk of CO2 leakage in the ROZ.

Modelling petroleum migration through microcrack propagation in transversely isotropic source rocks

SUMMARY To investigate primary petroleum migration through microfracturing of source rocks, we develop a theoretical multiphysics model incorporating simultaneous generation of oil and gas from kerogen, elastic anisotropy of the source rock and propagation of microcracks filled with oil and gas. The variations of excess fluid pressure in the crack and crack propagation distance with time are determined. A detailed parametric analysis is performed to study the sensitivity of petroleum migration behaviour to changes in the input parameters including kerogen type (chemistry of kerogen to oil/gas conversion), elastic anisotropy of source rocks, geothermal gradient and burial rate. Numerical results show that a microcrack in type III kerogen-bearing source rocks can attain greater length than in rocks containing type I and II kerogen which have higher oil potentials and transform to oil/gas much faster than type III kerogen. Elastic anisotropy of source rocks has a profound influence on the crack propagation distance, but only a marginal effect on the duration of crack propagation and the excess fluid pressure. The simulation also shows that higher geothermal gradients and fast burial reduce the crack propagation duration significantly, but excess pressure and final crack length are not sensitive to the variations of geothermal gradient and burial rate.

An integrated approach to the study of primary petroleum migration : U. Mann, in: Geofluids: origin, migration and evolution of fluids in sedimentary basins, ed J. Parnell, (Geological Society, London; Special Publication, 78), 1994, pp 233–260

An integrated approach to the study of primary petroleum migration : U. Mann, in: Geofluids: origin, migration and evolution of fluids in sedimentary basins, ed J. Parnell, (Geological Society, London; Special Publication, 78), 1994, pp 233–260

An integrated approach to the study of primary petroleum migration

Abstract The precise mechanism of primary petroleum migration has been elusive despite intensive investigation and discussion. There is more than one mechanism, and the pathways and efficiencies of individual mechanisms vary from case history to case history due to the variable abundances of micropores, macropores and fractures in source rocks as well as different sources for the build-up of a pressure gradient. Primary migration probably proceeds as diffusion through source rock micropores via mesopores to macropores and fractures. From there, a petroleum bulk phase develops, and moves along the macropore and fracture system, possibly together with aqueous solutions. In fact, many parameters influence petroleum transport out of a source rock, and all of them have seldom been checked by exploration geologists as most mature source rocks are inaccessible. In order to collect information about primary petroleum migration that is as complete as possible, an integrated approach consisting of sedimentology, petrophysics, organic geochemistry and numerical modelling should furnish geologically acceptable results: (i) by sedimentological methods, all potential primary migration pathways are identified, (ii) with the help of petrophysical methods, non-effective migration pathways are separated from effective pathways and excluded, (iii) organic geochemical results provide control and direct evidence for petroleum expulsion stage and efficiency, and (iv) numerical modelling finally quantifies all observed effects within the framework of the geological situation.

BASIN RICHNESS AND SOURCE ROCK DISRUPTION — A FUNDAMENTAL RELATIONSHIP?

Primary petroleum migration (expulsion from source rocks) remains the least understood parameter controlling the genesis of oil deposits. In spite of this lack of understanding, many petroleum geochemists (including this Author) have previously considered expulsion from organic‐rich, mature source rocks to be very efficient. This viewpoint results from Rock‐Eval analyses of organic‐rich source rocks, analyses which demonstrate a loss of hydrocarbon (HC) generation capacity, by significant reduction in Rock‐Eval hydrogen indices, as such rocks are progressively buried in sedimentary basins. However, this progressive loss of HC generation capacity is not matched by numerically‐equivalent increases either in Soxhlet‐extractable HCs or the Rock‐Eval S1 pyrolysis peak. Thus, we conclude that almost all generated HCs have migrated from the source rocks.Notwithstanding, the petroleum geochemistry of the Williston Basin (North America) and other considerations strongly suggest that this logic may be flawed. Instead, it appears that most generated HCs may not migrate far from their generation site, but instead are lost before source‐rock samples arrive at the laboratory for analysis. This loss occurs from a HC‐gas volume expansion, which results from the large pressure decreases in rock chips or cores during the trip up the wellbore in the course of drilling operations. The large volume expansions of these HC gases, which are cogenerated and coexist with oil in the source rocks, literally blow most generated oil in source rocks into the drilling mud during the trip uphole.If most generated HCs do in fact remain in or near their source rocks, then it can be hypothesised that source rocks must be physically disrupted before meaningful expulsion can occur. Faulting, with accompanying significant fracturing, would appear to be the optimum naturally‐occurring process for physical disruption of source rocks. If these hypotheses are valid. intensity of faulting in deeply‐buried HC “kitchens” containing mature source rocks should strongly correlate with increasing basin richness, as defined by recoverable oil divided by basin‐sediment area or volume.This possible relationship is examined in this Paper; and there is a strong correlation of increasing basin richness with increasing structural intensity over and adjacent to basin depocentres. This correlation thus supports the hypothesis that physical disruption of mature source rocks is a necessary, and previously unappreciated, controlling parameter for oil expulsion. If a relationship between physical disruption of source rocks and oil expulsion indeed exists, then significant implications would follow for:(1) basin resource assessment;(2) conventional oil exploration in frontier basins; and(3) the probable existence of very large, previously unappreciated, oil‐resource bases in fractured, self‐sourced shales.

Evidence of primary migration of condensate by molecular solution in aqueous phase in Yacheng Field, offshore South China

The composition of Yacheng condensate provides possible evidences of primary migration of petroleum by molecular solution in the aqueous phase. Aromatic hydrocarbons (HCs), especially benzene and toluene, make up a high percentage of the condensate. The abundance of each hydrocarbon (HC) in the condensate is mainly controlled by compound type and carbon number. The distribution of normal alkanes is discontinuous at C 16. Aromatic hydrocarbons are 3.8‰ isotopically heavier than the saturated hydrocarbons. The isoprenoid hydrocarbons are very abundant, especially pristane. The specific gravity of the Yacheng condensate is 0.85530 g cm −3, which is much higher than the average for condensates. These features are in good agreement with the HC solubilities in aqueous solution.

東北日本の堆積盆地における油のバイオマーカー

Crude oils and condensates from two sedimentary basins in Northeast Japan were analyzed for steroid and triterpenoid hydrocarbon biomarkers. Based on the biomarker parameters, the following conclusions were drawn concerning their maturities and sources:(1) The condensates are distinctly more mature than the crude oils. Some crude oils from the Akita-Yamagata basin are more immature than any of the oils from the Niigata basin. The stage of primary migration of petroleum in the former basin was possibly earlier than in the latter.(2) The source material for the oils from the Niigata basin is more terrigenous than that for the oils from the Akita-Yamagata basin. No systematic difference exists between the source material for the oils and that for the condensates from the Niigata basin.

PRIMARY PETROLEUM MIGRATION FROM SHALES WITH OXYGEN‐RICH ORGANIC MATTER

The mechanism of primary petroleum migration (PPM) is no better understood today than 20 years ago. Serious unanswered problems exist with the popular model of monophasic or “bulkphase” PPM from shales with oxygen‐rich organic matter (OM). Among these problems are: (1) How are molecularly dispersed hydrocarbons (HCs) gathered and concentrated into microdroplets and/or filaments for migration? (2) How are astronomical capillary‐displacement pressures overcome at the low burial temperatures (50d̀ to 60d̀C) over which bulk‐phase migration mechanisms have been proposed to operate? (3) What accounts for the significant compositional differences between crude oils and shale bitumen?The hypotheses of structured water and chromatographic adsorption were proposed to solve these problems. Both hypotheses are theoretically improbable. The two hypotheses contradict eachother and no evidence has been advanced of their existence in Nature. Substantial evidence from both Nature and the laboratory suggest that chromatographic adsorption does not exist. The hypothesis of structured water compounds the problem it was proposed to solve.PPM by gaseous solution at minimal burial temperatures of 150d̀C removes the problems associated with monophasic PPM. These burial temperatures, either alone or combined with microfracturing, remove the barriers created by high capillary‐displacement pressures. Microfracturing of shales must occur prior to and during PPM, no matter what the migration mechanism. Evidence of microfracturing exists from both the laboratory and Nature. The HC‐ gathering problem is solved by a difusive partitioning (“scavenging”) of HCs by aqueous solution through shale‐pore water to dispersed HC gas bubbles. Compositional differences between shale bitumen and crude oil are not only explained but are predicted by PPM by gaseous solution, and thus serve as evidence for PPM by gaseous solution. Laboratory data demonstrate that, even at mild burial temperatures, an HC‐gas phase has sufficient carrying capacity to account for oil deposits. Evidence of PPM by gaseous solution exists, from studies carried out in different sedimentary basins.The contention is invalid that if PPM by gaseous solution occurs at all, it only occurs at high maturation ranks, the only time when sufficient quantities of the C1 to C4 HC gases are thought to be generated. Significant generation of C1 to C7 (but especially C1 to C4) HCs commences in shales with oxygen‐rich OM at burial temperatures of 66d̀C (Ro = 0.40), as shown by data from both the laboratory and Nature. This generation at low maturation ranks has previously gone undetected because of inadequate analytical procedures. The contention is also invalid that the low gas‐oil‐ratios (GORs) of many oil pools invalidate the possibility of PPM by gaseous solution. Due to the high generation capacity of oxygen‐rich OM for the C1 to C4 gases, compared to C6+ HCs, GORs are more than adequate at the time of PPM to account for PPM. Post‐PPM processes significantly lower the GORs of oil deposits. In the Author's opinion, most HCs move from shales with oxygen‐rich OM by gaseous solution.

Production of liquid hydrocarbons from a geopressured gas well: Migration of dispersed hydrocarbons induced by brine flow

Several geopressured gas wells have produced small amounts of liquid hydrocarbons. They all produced an unusual gas condensate which differs dramatically from oil, containing predominantly light aromatic hydrocarbons. Two of the wells have also produced paraffinic oil. A series of hydrocarbon liquids produced from the Gladys-McCall No. 1 well (Cameron Parish, La.) is described here. The phase relations of brine, oil and gas in the producing formation and wellbore of this well were calculated using a three-phase, many-component computer program. A single gas-rich, dispersed hydrocarbon phase was present downhole, initially at some distance from the wellbore. The aromatic condensate represents the relatively water soluble hydrocarbons which dissolved in the brine. Prolonged production of brine from the well caused the hydrocarbon phase to move toward the well, ultimately leading to production of oil. Movement of less volatile hydrocarbons was retarded by adsorption, producing chromatographic separation. These data and conclusions were used to test several theories of primary migration of petroleum in nature. Whereas the aromatic condensate is derived from hydrocarbons dissolved in brine, it is very different from common petroleum, indicating a completely different origin for the latter. Expulsion of a dispersed hydrocarbon fluid from shale together with water is indicated, as in the “water flushing” theories of petroleum migration.

Geochemical effects of primary migration of petroleum in Kimmeridge source rocks from Brae field area, North Sea. II: Molecular composition of alkylated naphthalenes, phenanthrenes, benzo- and dibenzothiophenes

Variations with depth in the quantitative distributions of di- and tricyclic alkylaromatic hydrocarbons and sulfur heterocycles determined for a total of thirty-two core samples from two thick shale intervals and thirteen thin interbedded shale layers of the Upper Jurassic-age Kimmeridge Clay formation, Brae field area, North Sea, reveal, in part, the effects of depletion with hydrocarbon expulsion. Trends of increasing depletion with approach to the nearest shale-sandstone contacts, as documented by a decrease in carbon-normalized yields, are more distinctive for the alkylnaphthalenes as compared to the alkylphenanthrenes and alkyldibenzothiophenes, but less drastic than previously observed for long-chain alkanes ( cf. Part I: Leythaeuser et al., 1988). Lowest yields consistently were encountered at the outermost 1–2 metres of the thick shale intervals and for the thin shale layers where the relative expulsion efficiencies were much higher for C 15 to C 30 n-alkanes (80–95%) than for C 2 and C 3 alkylnaphthalenes (30–40%). In contrast, C 2 and C 3 alkylbenzothiophene yields were higher in these shale portions than further inside the thick shale which is interpreted to result from a post-expulsion selective replenishment from the adjacent oil accumulation. Expulsion was not associated with any detectable fractionation among C 1 and C 3 alkylnaphthalenes or C 1 and C 2 alkylphenanthrenes, as evidenced by a mass-balance approach and concentration ratios of individual alkylaromatic isomers commonly used as maturity indicators. Based on a reconstruction of the quantitative distributions of aromatic hydrocarbons and sulfur aromatics expelled from thin shale layers from early-mature through to mature stages of thermal evolution, it was verified that the Methylphenanthrene Index (MPI 1) and methyldibenzothiophene ratio (MDR) of the expelled oil reflects the average of the maturity levels during which the source rock has expelled petroleum.

Geochemical effects of primary migration of petroleum in Kimmeridge source rocks from Brae field area, North Sea. I: Gross composition of C 15+-soluble organic matter and molecular composition of C 15+-saturated hydrocarbons

In mature, oil-prone source rocks of the Upper Jurassic Kimmeridge Clay in the Brae field area. North Sea, the yield and the gross composition of solvent-extractabte pctroleum-likc compounds, as well as the molecular proportions of C 15+-saturated hydrocarbons, are primarily controlled by the effects of hydrocarbon expulsion during primary migration. Within sample series extending from shale centres towards adjacent reservoir sandstones, regular and pronounced yield decreases have been documented, as well as marked compositional changes for C 15+-soluble organic matter and its compound class fractions (saturated hydrocarbons, aromatic hydrocarbons, NSO-compounds) and for normal and isoprenoid alkanes. Relative migration losses indicating relative expulsion efficiencies were determined for the C 15+-alkanes. Throughout the outer five meters of thick shales relative expulsion efficiencies increase regularly and drastically for all compounds considered, e.g. exceeding 90% for the C 15+- n-alkanes in the outermost shale samples. Samples from thin (5–50 cm) shale layers interbedded between reservoir sandstones reveal similarly high expulsion efficiencies. For n-alkanes, the degree of depletion remains uniform throughout the molecular range C 15 to C 30 i.e. no compositional fractionation occurred during primary migration, which is interpreted to reflect expulsion of oil as a single phase fluid. A simple conceptual model is proposed to explain the mechanisms and relationships of generation and expulsion processes in time and space. A geochemically-relevant conclusion is that the C 15+-soluble organic matter recovered by solvent extraction of mature source rocks represents only a portion of the total non-volatile petroleum-like material originally generated.

Geochemical effects of petroleum migration and expulsion from Toarcian source rocks in the Hils syncline area, NW-Germany

For mature, oil-prone source rocks of Toarcian-age in the Hils syncline area, NW-Germany, the geochemical effects of primary migration of petroleum are shown. Expulsion has occurred at high efficiencies primarily via a network of macro- and micro-fractures. The effects of this fracture-controlled expulsion with respect to gross and molecular composition of C 15+-soluble organic matter are documented. Samples from fractured intervals have expelled total C 15+-soluble organic matter more efficiently than adjacent unfractured intervals. A systematic comparison of samples taken at cm-intervals away from macro-fractures reveals compositional gradients which are interpreted to reflect preferential depletion of saturated and aromatic hydrocarbons from the source rock shale into the fractures. Extracts of shale samples directly at fracture walls are enriched in NSO-compounds and highly polar asphaltene-like fractions. The composition of residual petroleum fluids extracted from the fracture-fill materials is variable. In some cases there is a close match with that of the shale at some distance away from the fractures. In other cases there is geochemical evidence to suggest that petroleum fluids were chemically altered during lateral flow along the fractures. Based on available geological and geochemical evidence a conceptual model is proposed to explain fracture development and fluid flow processes. Rapid heating by a nearby intrusive body at shallow depths when the Toarcian sediments still contained about 15–20% pore water has played an important role: overpressuring of aqueous pore fluids with abundant dissolved carbonate caused intense fracturing of the rich intervals in the mature Toarcian sections. Finally, the closely interdependent relationships between petroleum generation and petroleum migration processes are documented. Especially, the evolution of these relationships with maturity progress from immature (0.48% R m) to mature (0.68 and 0.88% R m) and overmature (1.45% R m) stages is shown. For example, in the maturity interval from 0.68 to 0.88% R m most of the measured shale compaction and porosity decrease is achieved by expulsion of petroleum. For some samples there is an inverse relationship between kerogen quality and extractable hydrocarbon yields suggesting that expulsion efficiencies were higher from the better-quality intervals because the petroleum achieved higher saturations and hence higher relative permeabilities.

Geochemical Effects of Primary Migration of Petroleum and Their Relevance with Respect to Mechanisms and Efficiencies of Expulsion: ABSTRACT

Geochemical analysis of the petroleum residing in the pore system of source rocks after primary migration has occurred holds the key to better understanding the mechanisms and efficiencies of expulsion processes. Indeed, the detailed recognition of migration phenomena and quantification of their effects have been made by a combined approach which (1) examines the composition variation of residual oil within individual bodies of source rocks and its relationship to, inter alia, petroleum in juxtaposed reservoir rocks and (2) makes a material balance of petroleum-related chemical species. This approach has been applied in three separate case studies, two of which address the economically most important source rock units of central and northwest Europe: the Lower Jurassic Toarcian shales from the Hils syncline area (Federal Republic of Germany) and the Upper Jurassic Kimmeridge Clay Formation from the Brae field area, North Sea (U.K. Sector). The third study is of a series of coals and interbedded sediments of Late Carboniferous age from the Ruhr area (Federal Republic of Germany). A synthesis of results has revealed some fundamental differences in migration mechanisms and efficiencies which are strongly linked to organic richness, kerogen quality, and source rock fabrics. These differences concern especially the degree ofmore » microfracturing and the role of gas as transport agents.« less

ORGANIC METAMORPHISM IN THE LOWER MISSISSIPPIAN‐UPPER DEVONIAN BAKKEN SHALES — II: SOXHLET EXTRACTION1

In this paper, we report on Soxhlet extraction (and subsequent related analyses) of 39 Lower Mississippian‐Upper Devonian Bakken shales from the North Dakota portion of the Williston Basin, and analyses of 28 oils from the Basin. Because of the influence of primary petroleum migration, no increase in the relative or absolute concentrations of hydrocarbons or bitumen was observed at the threshold of intense hydrocarbon generation (TIHG), or during mainstage hydrocarbon generation in the Bakken shales. Thus, the maturation indices that have been so useful in delineating the TIHG and mainstage hydrocarbon generation in other studies were of no use in this study, where these events could clearly be identified only by Rock‐Eva1 pyrolysis data.The type of primary petroleum migration operative in the Bakken shales led to the selective concentration of certain compound types in the oils of the basin, as well as the selective concentration of certain compound types in the shale extracts. The compositional differences between the crude oils and shale extracts provide evidence of the primary migration mechanism operative in this case, which is believed to have been gaseous solution, although the actual expulsion of oil from the rock, if observed, would probably have appeared to be bulk phase migration. Gaseous‐solution bulk‐phase primary petroleum migration also left organic‐geochemical imprints on the Bakken shales, observable by Soxhlet extraction and to a lesser extent by pyrolysis. The data of this study demonstrate that primary petroleum migration is a very efficient process.Four distinctive classes of saturated hydrocarbon gas chromatograms from the Bakken shales arose from facies, maturation, and primary migration controls. As a consequence of maturation, the percentage of saturated hydrocarbons increased in the shale extract at the expense of decreases in the resins and asphaltenes. Measurements involving resins and asphaltenes appear to be excellent maturation indices in the Bakken shales. Two different and distinct organic facies were present in immature Bakken shales.Rock‐Eval pyrolysis analysis was a critical research tool in this study; however, combined use of pyrolysis and Soxhlet extraction allowed organic‐geochemical features to be distinguished which would not have been possible by using either analysis alone.

Geochemical Effects and Efficiency of Primary Petroleum Migration in Interbedded Sand/Shale Sequences: ABSTRACT

Expulsion of petroleum from mature shale source rocks is not an exhaustive process. Invariably, some of the oil generated remains in the pore system of the source rock. The problems are to determine expulsion efficiency and to understand the type and magnitude of compositional fractionation associated with expulsion. To solve these problems a mass balance approach was used based on geochemical analysis of closely spaced core samples from interbedded sand/shale sequences. The content and molecular composition of extractable hydrocarbons from the center of thick shale units were compared to those from the edges of the units and from thinly interbedded shales. The main case histories for this study were two shale/sand sequences of Tertiary and Lower Cretaceous age from Svalbard, Norway, and one of Upper Carboniferous Westfalian age from the Ruhr area, Federal Republic of Germany. In each example, the shales had adequate organic matter contents (Type III kerogens) and maturity levels for hydrocarbon generation, and the interbedded sands had migrated hydrocarbon shows. Petroleum expulsion is higher from the edges of shale units and from thinly interbedded shales. N-alkaline expulsion shows pronounced compositional fractionation with greater expulsion of shorter chain-length molecules. Expulsion efficiencies reach 80-90% at peak generation. Pristane andmore » phytane are expelled to a lesser degree than n-alkane isomers, which increases the pristane/n-C/sub 17/ ratios in depleted samples. Expulsion efficiencies are not uniform; they vary as a function of proximity to migration avenues, such as sandstones, siltstone lenses, and fractures. Expulsion efficiencies are controlled by source rock richness and the extent of hydrocarbon generation. At equal maturity, Type II kerogen source rocks have higher expulsion efficiencies than Type III source beds.« less

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 C 5–C 15 range hydrocarbons and in saturated hydrocarbons in the C 15+ 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).