Primary Migration Of Hydrocarbons Research Articles

Hydrocarbon dominant migration direction and accumulation mode in Qijiang area, Sichuan Basin, China

The high‐quality hydrocarbon source rocks developed in the Longtan Formation of the Qijiang area and the good reservoir capacity of the overlying dolomite of the Jialingjiang Formation indicate that the area has great exploration potential. To clarify the hydrocarbon migration and accumulation characteristics of the area, the fluid potential of the Longtan Formation in the Qijiang area in the Early Jurassic was determined. The direction of the maximum negative gradient of the fluid potential indicates the direction of the primary migration of hydrocarbons, and the structural ridge theory is used to analyse the direction of the secondary migration of hydrocarbons. The results show that the fluid potential of the hydrocarbon source rocks of the Longtan Formation in the Early Jurassic is characterized by the alternate distribution of high potential zones and low‐potential zones. The central syncline, eastern syncline and western syncline are drainage zones and high potential zones, while the Shiyougou structural belt and Fo'er Ya structural belt are supply zones and low‐potential zones. The oil and gas fluids migrate from the east–west direction to the anticlinal zone for the primary migration; the structural ridge controls the secondary migration of oil and gas in the low‐potential area along the north–south direction, resulting in a zonal distribution of oil and gas traps along the structural ridge. By combining fluid potential and structural ridge characteristics to determine the dominant direction of primary and secondary hydrocarbon migration, a model of hydrocarbon migration and accumulation in the Qijiang area is developed, which provides an important basis for finding hydrocarbon reservoirs.

Qualitative mineralogical analysis of Barracuda exploration well in the offshore Mannar Basin (the Indian Ocean) using FTIR and XRD techniques

The Mannar Basin plays a vital role in petroleum exploration in Sri Lanka, and its Barracuda exploration well was drilled up to 4206 m in depth. The objective of the current study is to identify mineralogy using Fourier-transform infrared (FTIR) and X-ray diffraction (XRD) analyses. The FTIR and XRD analyses confirm the presence of quartz, feldspar, clay minerals (e.g., kaolinite, montmorillonite), calcite, and hematite in all marlstone and mudstone samples. These sedimentary rocks can be identified as potential petroleum source rocks in the Mannar Basin. Quartz, carbonate, and hematite cementations are directly reduced porosity and permeability, and thus primary migration of hydrocarbons from potential source rocks. Clay minerals act as a seal for hydrocarbon migrations in the Mannar Basin. A variety of dominant clay mineral assemblages allows the reconstruction of several paleoclimatic chronozones in warm/wet and arid climates. In contrast, feldspar dissolution promotes the primary migration of hydrocarbon from potential petroleum source rocks. Consequently, this study concluded that common minerals such as quartz, carbonate, and hematite are associated with the trapping and binding processes of hydrocarbons.

Experimental modelling of primary migration in a layered, brittle analogue system

A 2D Hele-Shaw cell was built to study microfracture nucleation, growth, and network formation during internal fluid production. Fluid is slowly produced into a low permeability solid, which leads to a local fluid pressure increase that controls the nucleation of microfractures that grow and then connect to create flow pathways. This process occurs during the primary migration of hydrocarbons in source rocks, which is the main topic of our study. It may also occur in other geological systems, such as the expulsion of water during dehydration of clay-rich sediments in sedimentary basins or serpentinite rocks in subduction zones and the transport of magmatic melts. Our system consists of a transparent, brittle gelatin material mixed with yeast and sugar. The consumption of sugar by yeast leads to CO2 formation, resulting in microfracture nucleation and growth. We varied three parameters, (1) anisotropy (i.e., number of layers), (2) lateral sealing, and (3) rate of fluid production. We tracked fluid movement through the opening and closing of microfractures within the system. Microfracture nucleation density is similar in a layered system to previous studies (0.45 microfracture per cm2). However, we observed that lateral confinement (0.31 microfracture per cm2) and rate of expulsion (0.99 microfracture per cm2) affect nucleation density and the geometrical characteristics of the microfracture network. The size, extent, and geometry of the microfracture network are dependent on all three parameters investigated, where lateral confinement and a higher rate of expulsion result in greater microfracture network connectivity. Layers control the angle of intersection between microfractures. Furthermore, layering and sealing have an impact on fracture topology. Results also show that the microfracture pattern significantly influences the fluid expulsion rate. Our results have direct applications to understanding how fluid migration occurs in low-permeability rocks through the development of a connected microfracture network produced by internal fluid generation.

Application of aromatic/aliphatic ratios analysis in revealing migration pathways in unconventional reservoirs: A case study of the Bakken Shale

The ratio of aromatic to aliphatic (AR/AL) hydrocarbons was used to investigate migration pathways in tight unconventional reservoirs. Analytical methods, including organic petrography and geochemistry, programmed pyrolysis, solid bitumen reflectance, and liptinite autofluorescence, were employed to generate regional thermal maturity maps. While AR/AL ratios are known to increase with thermal maturity, a comparison of AR/AL ratios with thermal maturity indices as well as regional thermal maturity maps shows no significant correlation to other known thermal maturity proxies (i.e., Tmax or VRo-Eq) for the Bakken Shale samples. Taking into account the concept of “size and shape” filtration from a previous study, the observed inconsistency between AR/AL ratios and thermal maturity indicators could be explained reasonably, where, based on this concept, the aliphatics are able to migrate more easily through the shale's tight media compared to the aromatics, which would remain in situ or migrate only very short distances because of their size and shape. This indicates that the inconsistency between AR/AL ratios and thermal maturity indicators is related to the disproportionate rate of migration of aliphatic and aromatic hydrocarbons in the Bakken Shale. To evaluate the potential application of using AR/AL ratio chemical analyses to reveal the possible migration pathways, initial values for total organic carbon (TOCo) and S1 (S1expelled) were calculated for the thermally immature Bakken source rock. Comparing the regional distribution maps of S1expelled and the present values of S1 could reveal the geospatial displacements of generated hydrocarbons and, therefore, the possible pathways of hydrocarbon primary migration. Comparing the AR/AL ratio regional maps with the attained migration pathway based on S1 and S1expelled regional maps reveals an acceptable correlation in terms of the general trend. In this regard, AR/AL ratios exhibit higher values in the locations of the higher concentrations of calculated S1expelled distribution maps and lower values in the location of the higher concentrations of programmed pyrolysis-derived S1 distribution maps. These outcomes confirm that AR/AL ratios could be used as a potential proxy in revealing the possible migration pathways in unconventional reservoirs.

A model of fluid expulsion from compacting tight sedimentary rocks based on the Toggle-Switch algorithm

Expulsion of fluids from tight rocks is an important process in sedimentary basins for phenomena such as distribution of overpressure and primary migration of hydrocarbons. This paper shows that the “Toggle Switch” (TS) algorithm of Miller and Nur is well-suited to model expulsion of brine by hydraulic fracturing from tight rocks undergoing compaction. Local random overpressure is generated in the TS algorithm using a void ratio function with random compaction length. The TS algorithm equilibrates critical fluid pressure by local exchange of excess fluid. We show that the algorithm gives net migration of fluid upwards, because the least compressive stress is decreasing towards the surface. The random void ratio makes the total expulsion rate from the layer intermittent. In the limit of zero cell size the expulsion rate approaches a mean value. When the rock has a random strength, it is shown that critically pressured clusters remain after the TS algorithm has been applied. The implementation of the algorithm is mass conservative, which ensures that the expelled mass is exactly the mass of pore fluid lost by compaction. Expressions are derived for the rate of fluid expulsion and for an effective fracture permeability.

Deep fluids and their role in hydrocarbon migration and oil deposit formation exemplified by supercritical СO2

ABSTRACTHydrocarbon migration mechanism into a reservoir is one of the most controversial in oil and gas geology. The research aimed to study the effect of supercritical carbon dioxide (СО2) on the permeability of sedimentary rocks (carbonates, argillite, oil shale), which was assessed by the yield of chloroform extracts and gas permeability (carbonate, argillite) before and after the treatment of rocks with supercritical СО2. An increase in the permeability of dense potentially oil-source rocks has been noted, which is explained by the dissolution of carbonates to bicarbonates due to the high chemical activity of supercritical СО2 and water dissolved in it. Similarly, in geological processes, the introduction of deep supercritical fluid into sedimentary rocks can increase the permeability and, possibly, the porosity of rocks, which will facilitate the primary migration of hydrocarbons and improve the reservoir properties of the rocks. The considered mechanism of hydrocarbon migration in the flow of deep supercritical fluid makes it possible to revise the time and duration of the formation of gas–oil deposits decreasingly, as well as to explain features in the formation of various sources of hydrocarbons and observed inflow of oil into operating and exhausted wells.

Structural and dynamic distribution patterns of oil fields in the central part of the Volga-Ural anteclise

Tectonical and development features of the central part of the Volga-Ural anteclise and the Sura-Kama (SK) shear zone are considered in connection with the distribution patterns of oil fields. Based on the geological and structural data, it is found that the SK zone is a deep fault of a heterogeneous structure, which has signs of the long-term multistage development. At the plate stage, the SK zone developed under kinematic inversion and subsequent transpression and transtension deformations. We propose a model showing that during the transtension stages, deformations in the SK zone contributed to the primary migration of hydrocarbons in the Devonian domanic formations and their secondary redistribution. Within the SK zone, permeability was increased, and the zone itself acted as a concentrator of these formations in local decompression structures. Fault structures in the SK zone closed during the transpression stages; their reservoir properties were decreased; and hydrocarbons were squeezed predominantly in the lateral direction along the reservoirs in the area of dynamic unloading. At the eastern termination of the SK zone, the unique Arlan oil field was formed, wherein hydrocarbons were accumulated in conditions of alternating stresses between the sectors compensating shear displacements at the flanks of the zone. The unique Romashkinsky oil field was formed in the apical part of the South Tatar arch during its long-term uplifting and decompression, which contributed to progressive migration and accumulation of hydrocarbons from the transpression sector of SK zone. The proposed structural-dynamic model and ideas about compression – decompression regularities of hydrocarbon redistribution in the shear zones can be used for prediction and detection of new deposits. In particular, the dynamic analogues of the Arlan oil field in the east part of the SK zone can be found within the poorly studied western flank of this zone.

Silica diagenesis promotes early primary hydrocarbon migration

AbstractWe present evidence that hydrocarbon source rocks can be preconditioned for primary hydrocarbon migration at an early stage of catagenesis by pore-scale processes linked to silica diagenesis. The evidence comes from a detailed petrographic and geochemical study of the Jordan Oil Shale (JOS), an immature to early mature, Upper Cretaceous to Paleogene source rock developed on the platform regions of central and southern Jordan. Diagenesis of biogenic silica led to silicification of the source rock interval and the growth of chert nodules. Localization of bitumen veins in reaction rims around these nodules is interpreted to indicate that silica diagenesis promotes the early mobilization of hydrocarbons from the geochemically identical, disseminated bitumen within the host mudstones. We propose a model in which early-formed bitumen migrated into neoforming mode I fractures that formed as a result of the crystallization pressure imposed from the growing chert nodule. Hydraulic fracturing occurred under elevated bitumen fluid pressures that approached lithostatic stress values under burial depths of the order of 1000 m. The recognition that silica diagenesis can promote the early migration of neoforming bitumen raises the possibility that primary hydrocarbon migration may occur earlier and at shallower depths than predicted by kinetic modeling approaches wherever silica diagenetic reactions are coeval with catagenesis.

The pore structural evolution of the Marcellus and Mahantango shales, Appalachian Basin

Abstract The generation and primary migration of hydrocarbons in organic-rich shale leaves void space in organic matter, which is the porosity associated with organic matter commonly observed under scanning electron microscope (SEM). In this study, Middle Devonian black shale core samples were collected from three wells penetrating the organic-rich Marcellus Shale and the organic-lean Mahantango Formation in Pennsylvania and West Virginia. Pyrolysis, ion milled SEM and low-pressure nitrogen adsorption analysis were conducted to investigate the organic richness and the properties of the pore system. Vitrinite reflectance (Ro) values in the range of 1.36%–2.89% represent a maturity spectrum covering the wet-gas to post-mature zones. In general, the pore system is composed of organic matter-hosted pores and mineral-hosted pores. However, the dominant pore types and pore sizes vary stratigraphically across lithology and abundance of organic matter. All the organic matter observed in this study shows an amorphous occurrence. Pore space between mineral grains (both silt-size and clay-size) can be filled by organic matter, which contains secondary porosity generated by thermal cracking of kerogen. Mineral-hosted pores are concentrated in organic-lean samples in which secondary organic matter could not fill most of the primary pore space. The destruction of primary mineral-hosted pores and the generation of secondary organic matter-hosted pores were observed. TOC values show positive correlations with the porosity, specific surface area, and the abundance of micropores. Increasing thermal maturity correlates with a significant decrease of pore volume and surface area, primarily through diminishing or vanishing of micropores. The richness and thermal maturity of organic matter in organic-rich Devonian shale can be effective parameters for evaluation of reservoir quality and upscaling the appraisal.

Fluid expulsion and microfracturing during the pyrolysis of an organic rich shale

During progressive burial, low permeability organic-rich shale rocks evolve chemically and physically as the temperature and stress increase and organic matter matures. The transformation of organic matter into hydrocarbon, followed by its expulsion into secondary migration pathways along which it is conveyed into reservoirs rocks, is a coupled process that involves chemical reactions, changes in volume and stress leading to the nucleation and growth of microfractures, the opening and closing of these microfractures, and fluid transport through them. Primary migration was studied using an experimental setup that was designed to measure changes in fluid pressure, which are correlated with organic matter maturation and hydrocarbon expulsion. The setup consisted of a pressurized autoclave which was externally heated. Shale samples were confined, under an initially low confining pressure and an applied differential stress (0.18 MPa), and heated to temperatures of 210–320 °C. Changes in temperature, static pressure (pressure measured using a linear response transducer) and dynamic fluid pressures (measured using a piezoelectric differential transducer) in the autoclave chamber were monitored and recorded during each experiment. In the higher part of the temperature range, fluid produced by kerogen maturation and the concomitant formation of microfractures increased volumetric expansion of the shale. Power spectral densities of the fluid pressure signals were calculated and a conceptual model is proposed to explain the dynamics of fluid expulsions. While a power law distribution of frequencies of pressure burst amplitudes was identified, the frequencies of time intervals between successive expulsion events (waiting times) decrease monotonically with increasing waiting time. Co-generation of gas and liquid hydrocarbon was evidenced. Several samples were imaged after kerogen maturation using X-ray microtomography, and the data confirm the existence of a percolating network of microfracture that controls the primary migration of hydrocarbons.

Use of derivatives to assess preservation of hydrocarbon deposits

The paper considers the calculation of derivatives along the surface of a modern and paleostructure map of a Tl2-b formation top used to forecast the preservation of oil and gas deposits in traps according to 3D seismic survey via statistical methods. It also suggests a method to evaluate morphological changes of the formation top by calculating the difference between derivatives. The proposed method allows analyzing structural changes of the formation top in time towards primary migration of hydrocarbons. The comprehensive use of calculated indicators allowed ranking the prepared structures in terms of preservation of hydrocarbon deposits.

Types, characteristics and effects of natural fluid pressure fractures in shale: A case study of the Paleogene strata in Eastern China

Paleogene organic-rich shales from the Dongying Sag and Zhanhua Sag of Jiyang Depression in Bohai Bay Basin and Northern Jiangsu Basin in Eastern China are studied, to categorize the types and characteristics of natural fluid pressure fractures and their effects on hydrocarbon primary migration. The study shows that fluid overpressure is the main reason for the formation of natural fluid pressure fractures. The natural fluid pressure fractures include three types, early drainage fractures, bedding-parallel vein fractures, and hydrocarbon generation and expulsion fractures. Early drainage fractures have the typical characteristics of snaking morphology, bedding-parallel vein fractures are filled with fibrous calcite vein and coexist with organic matter, and hydrocarbon generation and expulsion fractures generated by hydrocarbon-generating pressurization of kerogen are the key to episodic expulsion of organic-rich shale. Fractures of multiple origins, such as natural fluid pressure fractures, bedding fractures and structural fractures, accumulate gradually, forming interconnected fracture networks which are significant primary migration pathways and reservoir space, act as the seepage channel in the process of multi-scale seepage and are the premise of realizing volume fracturing in shale reservoirs.

The evolution of Devonian hydrocarbon gases in shallow aquifers of the northern Appalachian Basin: Insights from integrating noble gas and hydrocarbon geochemistry

The last decade has seen a dramatic increase in domestic energy production from unconventional reservoirs. This energy boom has generated marked economic benefits, but simultaneously evoked significant concerns regarding the potential for drinking-water contamination in shallow aquifers. Presently, efforts to evaluate the environmental impacts of shale gas development in the northern Appalachian Basin (NAB), located in the northeastern US, are limited by: (1) a lack of comprehensive “pre-drill” data for groundwater composition (water and gas); (2) uncertainty in the hydrogeological factors that control the occurrence of naturally present CH4 and brines in shallow Upper Devonian (UD) aquifers; and (3) limited geochemical techniques to quantify the sources and migration of crustal fluids (specifically methane) at various time scales. To address these questions, we analyzed the noble gas, dissolved ion, and hydrocarbon gas geochemistry of 72 drinking-water wells and one natural methane seep all located ≫1km from shale gas drill sites in the NAB. In the present study, we consciously avoided groundwater wells from areas near active or recent drilling to ensure shale gas development would not bias the results. We also intentionally targeted areas with naturally occurring CH4 to characterize the geochemical signature and geological context of gas-phase hydrocarbons in shallow aquifers of the NAB. Our data display a positive relationship between elevated [CH4], [C2H6], [Cl], and [Ba] that co-occur with high [4He]. Although four groundwater samples show mantle contributions ranging from 1.2% to 11.6%, the majority of samples have [He] ranging from solubility levels (∼45×10−6cm3 STP/L) with below-detectable [CH4] and minor amounts of tritiogenic 3He in low [Cl] and [Ba] waters, up to high [4He]=0.4cm3 STP/L with a purely crustal helium isotopic end-member (3He/4He=∼0.02 times the atmospheric ratio (R/Ra)) in samples with CH4 near saturation for shallow groundwater (P(CH4)=∼1 atmosphere) and elevated [Cl] and [Ba]. These data suggest that 4He is dominated by an exogenous (i.e., migrated) crustal source for these hydrocarbon gas- and salt-rich fluids. In combination with published inorganic geochemistry (e.g., 87Sr/86Sr, Sr/Ba, Br−/Cl−), new noble gas and hydrocarbon isotopic data (e.g., 20Ne/36Ar, C2+/C1, δ13C-CH4) suggest that a hydrocarbon-rich brine likely migrated from the Marcellus Formation (via primary hydrocarbon migration) as a dual-phase fluid (gas+liquid) and was fractionated by solubility partitioning during fluid migration and emplacement into conventional UD traps (via secondary hydrocarbon migration). Based on the highly fractionated 4He/CH4 data relative to Marcellus and UD production gases, we propose an additional phase of hydrocarbon gas migration where natural gas previously emplaced in UD hydrocarbon traps actively diffuses out into and equilibrates with modern shallow groundwater (via tertiary hydrocarbon migration) following uplift, denudation, and neotectonic fracturing. These data suggest that by integrating noble gas geochemistry with hydrocarbon and dissolved ion chemistry, one can better determine the source and migration processes of natural gas in the Earth’s crust, which are two critical factors for understanding the presence of hydrocarbon gases in shallow aquifers.

Petrophysical implications of source rock microfracturing

Hydrocarbon generation induced microfracturing in source rocks is important affecting both primary migration of hydrocarbons, and unconventional shale plays. In this study petrographic observations, Rock-Eval and total organic carbon content (TOC) data, and log-derived physical properties were analyzed in order to evaluate eventual petrophysical implications of microfracturing induced by hydrocarbon generation.Petrographically, evidences of microfracturing both normal and parallel to bedding have been found. Horizontal microfractures typically cross cut each other at an angle between 30 and 90°. Horizontal microfractures are readily imaged compared to vertical microfractures. Vertical microfractures were clearly observed only in rare cases in samples with a high degree of microfracturing. In the case of moderate microfracturing, the vertical component of microfractures may be too small to be detectable using conventional microscopy techniques. Longer vertical components of the microfractures may be facilitated by higher TOC and particularly dense laminated organic matter fabric, as well as higher thermal maturity levels. Clay minerals, particularly smectites are also playing a role in reducing permeability and thereby increasing the local pressure generated by hydrocarbon generation eventually resulting in microfracturing.Log-derived petrophysical properties particularly P-wave velocity (Vp) and formation resistivity can give information on microfracturing potential even though the techniques can't resolve the microfractures directly. Vp has been postulated to be sensitive to organic matter quantity and fabric, whereas formation resistivity is largely governed by fluid content and clay minerals. A reverse trend of increasing resistivity with decreasing Vp was found and is linked to higher hydrocarbon saturation and TOC and/or dense laminated fabric of organic matter favoring microfractures. The implications of the log-derived petrophysical results are in agreement with the direct petrographic observations. Formation resistivities in the source rocks, however, are lower than those observed in non-clay dominated hydrocarbon saturated intervals. This indicate that low permeable organic rich source rocks with a high clay content, particularly smectites, may facilitate formation of the hydrocarbon filled vertical microfractures even at relatively low thermal maturities.

Compaction and Migration of Hydrocarbons in East Baghdad Oil Field

An attempt is done to present a simple concept to combine the geochemical results with the concept of compaction- abnormality, reflecting a high variation in the porosity and internal pore pressure. The different compaction levels and the variation of the bulk volume may lead to the expulsion of fluids both hydrocarbon and interstitial H2O from high potential zones towards low potential zones, or in other words from low porosity towards high porosity areas. Furthermore, the both formations (Ratawi and Zubair) of lower Cretaceous age showing compaction trend as well as fluid expulsion current with a NW-SE trend of the primary hydrocarbon migration, while the sedimentary basin revealing a deepening towards the southern eastern part of the anticline structure. A change in thickness and the facieses of the rock packages is manifested. The horizontal porosity distribution of shales in Ratawi formation particularly in the upper part (15m thick) reveal differential compaction and such a mechanism is responsible for the kinetic of fluid and gas.

Oil-Gas Transformation Induced Subcritical Crack Propagation and Coalescence in Petroleum Source Rocks

The present work describes a multi-physics model to investigate subcritical propagation of initially oil-filled, sub-horizontal collinear microcracks driven by the excess pressure induced by the conversion of oil to gas in a petroleum source rock under continuous burial. The crack propagation distance, propagation duration, crack coalescence and excess pressure in the crack are determined using a finite difference scheme that couples linear elastic fracture mechanics, oil-gas transformation kinetics and an equation of state for the gas. The numerical results for a shale source rock with typical properties show that when the crack spacing parameter b/a0 is greater than 3, where a0 is the half crack length and b the half distance between the crack centers, the cracks do not coalesce, and the duration of gas-driven crack propagation is governed by the transformation kinetics because the oil-gas conversion rate is much slower than the subcritical crack propagation rate. The collinear cracks coalesce for smaller crack spacing and the crack propagation duration may reduce significantly due to crack interactions. The multi-physics model presented in this work together with our previous model for crack propagation during the conversion of solid kerogen to oil indicates that self-propagating microcracks resulting from the buildup of excess fluid pressure during hydrocarbon generation may serve as effective pathways for primary migration of hydrocarbons.

A 4D Synchrotron X-Ray-Tomography Study of the Formation of Hydrocarbon- Migration Pathways in Heated Organic-Rich Shale

SummaryRecovery of oil from oil shales and the natural primary migration of hydrocarbons are closely related processes that have received renewed interest in recent years because of the ever tightening supply of conventional hydrocarbons and the growing production of hydrocarbons from low-permeability tight rocks. Quantitative models for conversion of kerogen into oil and gas and the timing of hydrocarbon generation have been well documented. However, lack of consensus about the kinetics of hydrocarbon formation in source rocks, expulsion timing, and how the resulting hydrocarbons escape from or are retained in the source rocks motivates further investigation. In particular, many mechanisms have been proposed for the transport of hydrocarbons from the rocks in which they are generated into adjacent rocks with higher permeabilities and smaller capillary entry pressures, and a better understanding of this complex process (primary migration) is needed. To characterize these processes, it is imperative to use the latest technological advances. In this study, it is shown how insights into hydrocarbon migration in source rocks can be obtained by using sequential high-resolution synchrotron X-ray tomography. Three-dimensional images of several immature “shale” samples were constructed at resolutions close to 5 μm. This is sufficient to resolve the source-rock structure down to the grain level, but very-fine-grained silt particles, clay particles, and colloids cannot be resolved. Samples used in this investigation came from the R-8 unit in the upper part of the Green River shale, which is organic rich, varved, lacustrine marl formed in Eocene Lake Uinta, USA. One Green River shale sample was heated in situ up to 400°C as X-ray-tomography images were recorded. The other samples were scanned before and after heating at 400°C. During the heating phase, the organic matter was decomposed, and gas was released. Gas expulsion from the low-permeability shales was coupled with formation of microcracks. The main technical difficulty was numerical extraction of microcracks that have apertures in the 5- to 30-μm range (with 5 μm being the resolution limit) from a large 3D volume of X-ray attenuation data. The main goal of the work presented here is to develop a methodology to process these 3D data and image the cracks. This methodology is based on several levels of spatial filtering and automatic recognition of connected domains. Supportive petrographic and thermogravimetric data were an important complement to this study. An investigation of the strain field using 2D image correlation analyses was also performed. As one application of the 4D (space + time) microtomography and the developed workflow, we show that fluid generation was accompanied by crack formation. Under different conditions, in the subsurface, this might provide paths for primary migration.Key words in this work include 4D microtomography, 3D image processing, shale, strain field analysis, kerogen, petroleum generation, primary migration, petrography, and thermogravimetry.

Stable carbon isotopic fractionation of individual n-alkanes accompanying primary migration: Evidence from hydrocarbon generation–expulsion simulations of selected terrestrial source rocks

Abstract The effect of isotopic fractionation during primary migration of hydrocarbons from coals is rarely noticed because it overlaps with the isotopic effects of maturation. In this research, geological chromatography-like effects and possible physical isotopic fractionation effects on n -alkanes during primary migration from four coals and one mudstone were studied through two types of generation–expulsion simulations (generation–expulsion simulations I and II). In order to monitor the kinetic isotopic fractionation effect during primary migration and to differentiate the isotopic effects of primary migration from the isotopic effects of maturation, generation–expulsion simulation was upgraded in two aspects, source rock was separated into at least five layers, and deuterated n -C 15 D 32 was added to the initial layer of the source rock (simulation II). The experimental results suggested that all terrestrial source rocks exhibit significant geological chromatography-like effects in generation–expulsion simulation. Expulsion efficiencies shown by vitrinite-rich coals are much lower than algal cannel, fusinite-rich coal and mudstone. There also exist significant physical isotopic fractionation effects in hydrocarbon primary migration processes from vitrinite-rich coals, but there is no significant isotopic fractionation effect from fusinite-rich brown coal and mudstone. Pore structure and specific surface area of source rock samples were measured by gas adsorption of both N 2 and CO 2 . This indicated that vitrinite-rich coals have a higher proportion of microporosity. The differences in pore structure and adsorptive capacity of source rocks may be responsible for differences in expulsion efficiencies and isotopic fractionation effects in generation–expulsion simulations. The isotopic fractionation effect due to primary migration should be considered in making oil-source correlation when vitrinite-rich coals are concerned.

Occurrence, thermal evolution and primary migration processes derived from studies of organic matter in the Lucaogou source rock at the southern margin of the Junggar Basin, NW China

The Lucaogou Formation carbonate-rich oil shale source rock is exposed at the southern margin of the Junggar Basin, Xinjiang, NW China. We have sampled it in detail and conducted microstructural, mineralogical and geochemical studies, including thin section petrography, UV fluorescence petrography, X-ray diffraction, vitrinite reflectance, bitumen reflectance, fluid inclusion analysis and Raman spectroscopy. Organic matter is disseminated through the carbonate-bearing siltstone source rocks and concentrated in numerous bedding parallel stylolites and in two sets of carbonate veins, one along bedding parallel fractures and the other cross-cutting stylolites and bedding. The research about maturity of organic matter finds vitrinite reflectance values increase from the dispersed kerogen (0.64%) to the stylolites (the one of oriented vitrinite is 0.72% and the one of migrated bitumen is 2.38%); Homogenization temperatures of fluid inclusions in veins containing hydrocarbon fluid inclusions show an increase from 178.5°C in the bedding parallel veins to 222°C in the cross-cutting veins, confirmed by Raman spectroscopy. These results support a model of progressive heating accompanied by fluid loss during later stages of thermal maturation of source rock and the onset of primary migration. Obviously, the occurrence of organic matter is the trace of hydrocarbon primary migration, and the bedding lamination surfaces and cross-cutting fissures are the principal pathways of hydrocarbon-bearing fluids migration. Bedding lamination surfaces evolved into stylolites along the earliest primary migration pathways, followed by bedding parallel and cross-cutting fissures.

Volcanic reservoir rocks of northwestern Honshu island, Japan

Abstract The main Japanese oil producing region lies on the Japan Sea side of northern Honshu island. Although the total reserve is small and production supplies only threetenths of a percent of total Japanese oil consumption, it has two distinguishing features: (1) the main reservoir rocks are volcanic, pyroclastic, or tuffaceous, and (2) primary oil and gas migration seems to have taken place downward from the overlying source rocks. Marine volcanic activity since 15 Ma formed the main reservoir sections together with significant secondary porosity development. Thick and continuous deposition of organic-rich shales and mudstones followed and lower parts of these fine-grained rocks became the main source rocks. The principal direction of primary hydrocarbon migration occurred vertically downward from them. These fine-grained rocks seem to have acted as pressure seals as well as capillary seals over the oil/gas saturated zones below.