Hydrocarbon Expulsion Research Articles

Organic geochemistry of the Upper Triassic T3x5 source rocks and the hydrocarbon generation and expulsion characteristics in Sichuan Basin, central China

The Upper Triassic Xujiahe Formation is a key target layer for development of tight sandstone gas reservoirs in the Sichuan Basin. Most of the previous work focused on the main reservoirs such as T3x2 and T3x4 with lack of research attention on T3x5, an equally important source-reservoir unit. Here we examine the organic matter and source rock distribution in the T3x5 using rock pyrolysis, asphalt extraction, and gas chromatography. The thickness of T3x5 source rocks reduces from west and northwest Sichuan Basin to east and southeast Sichuan Basin. The main sedimentary facies are salt lakes and deltas, of which the organic matter originated from aquatic organisms and a small amount of terrestrial matter. The abundance of total organic carbon (TOC) in T3x5 is relatively high, at values of 0.07%–7.2%. According to the vitrinite reflectance (Ro), pyrolysis, and gas chromatography measurement results, the T3x5 source rocks are at the stage of mature to over-mature, and their hydrocarbon expulsion threshold and hydrocarbon expulsion peak correspond to Ro of 1.05% and 1.23%, respectively. Furthermore, a hydrocarbon generation center and a hydrocarbon expulsion center are formed horizontally, with the maximum hydrocarbon generation intensity of 50 × 108 m3/km2 and the maximum hydrocarbon expulsion intensity of 48 × 108 m3/km2. The natural gas resource is 3.19–5.36 × 1012 m3, indicating great exploration potential.

Poroelasticity of Methane-Loaded Mature and Immature Kerogen from Molecular Simulations.

While hydrocarbon expulsion from kerogen is certainly the key step in shale oil/gas recovery, the poromechanical couplings governing this desorption process, taking place under a significant pressure gradient, are still poorly understood. Especially, most molecular simulation investigations of hydrocarbon adsorption and transport in kerogen have so far been performed under the rigid matrix approximation, implying that the pore space is independent of pressure, temperature, and fluid loading, or in other words, neglecting poromechanics. Here, using two hydrogenated porous carbon models as proxies for immature and overmature kerogen, that is, highly aliphatic hydrogen-rich vs highly aromatic hydrogen-poor models, we perform an extensive molecular-dynamics-based investigation of the evolution of the poroelastic properties of those matrices with respect to temperature, external pressure, and methane loading as a prototype alkane molecule. The rigid matrix approximation is shown to hold reasonably well for overmature kerogen even though accounting for flexibility has allowed us to observe the well-known small volume contraction at low fluid loading and temperature. Our results demonstrate that immature kerogen is highly deformable. Within the ranges of conditions considered in this work, its density can double and its accessible porosity (to a methane molecule) can increase from 0 to ∼30%. We also show that these deformations are significantly nonaffine (i.e., nonhomogeneous), especially upon fluid adsorption or desorption.

Enrichment conditions of Hetaoyuan Formation shale oil in Biyang Depression, China

In this paper, the data of thin section, organic petrology, geochemistry, lithology and porosity were used to investigate enrichment conditions of Hetaoyuan Formation shale oil in the Biyang Depression. The results show the shale oil is a kind of low-maturity oil with medium density and low viscosity, and main factors controlling shale oil enrichment include total organic content (TOC), formation pressure, lithofacies and effective reservoirs. Shales in the fifth organic-rich interval are developed widely with large thickness (reach up to 150 m), high TOC content (2.0–4.68%), better organic matter types (type I and II1) and appropriate thermal maturity (usually larger than 0.5%), which are beneficial to generate much hydrocarbon, and volume expansion causes overpressure in source rock, especially in sections with low hydrocarbon expulsion efficiency due to less fractures. Free hydrocarbons S1 values increase with TOC contents, and significant overpressure correlates with the larger OSI (S1/TOC × 100) values and porosity. Well-developed calcareous shales and argillaceous shales with silty shale interlayers have better porosity, and effective pores (throat diameters greater than 10 nm) contribute to 47.5% of the total volume.

Determination method of shale gas content: A case study in the Ordos Basin, China

Three shale samples, which were from MF-1 well (a) and MF-2 well (b) in the northern Ordos Basin of China and Yan'an Formation of Jurassic coal measure strata of J601 well (c) in the western edge of the Ordos Basin, were taken for thermal simulation and rock pyrolysis experiments. The rules of hydrocarbon generation production and S2 varied with the increase in thermal maturity (Ro), and the relationship between S2 and gaseous hydrocarbon generation production were analyzed. The analytical results indicated that as the Ro increased, the liquid hydrocarbon production of the shale samples first increased and then decreased, while the gaseous hydrocarbon production and total hydrocarbon production increased, and the S2gradually decreased. Gaseous hydrocarbon production increased as S2 decreased, and there was a two-stage negative linear correlation between S2 and gaseous hydrocarbon production. The gaseous hydrocarbon production increased slowly when the Ro value was below 0.8% and rapidly increased after this threshold was met. During the process of the hydrocarbon generation of the shale in the Ordos Basin, the evolution phase could be divided into three stages: the immature stage of producing liquid hydrocarbon, the mature stage of producing gaseous and liquid hydrocarbon, and the overmature stage of gaseous hydrocarbon thermal cracking. Considering the hydrocarbon expulsion efficiency of the shale samples, the total organic carbon (TOC) content had a positive logarithmic correlation with the shale gas content (the gaseous hydrocarbon production minus the expulsed gaseous hydrocarbon production). The hydrocarbon generation potential and gas content increased with the increase of TOC. With the knowledge of the shale samples' TOC content, the shale gas content of the sampling layer could be preliminarily determined based on the regression equations of TOC and gas content. The exploration potential of the shale layer could be evaluated according to the gas content calculation, after considering the standards for the shale gas favorable area and the target area gas content.

Determining gas expulsion vs retention during hydrocarbon generation in the Eagle Ford Shale using noble gases

The recent proliferation of tight or unconventional petroleum bearing reservoirs as an energy resource enables a more detailed investigation of the geochemical behaviour of these systems. In addition, it provides an opportunity to improve our understanding of low-permeability crustal fluid systems at depth. Organic-rich shales are not only the source-rocks in conventional petroleum systems, but potential seals, which may be important for the trapping and storage of CO2 and/or nuclear waste. The use of noble gas isotopes as tracers of fluid provenance and physical exchange processes is well established in other crustal fluid systems. Noble gas concentrations and isotopic characteristics were determined in 10 natural gas samples produced from the Eagle Ford shale, Texas, along with the concentration and δ13C and δD of hydrocarbon gases. By sampling gases produced directly from unconventional reservoirs we are able to determine their residence time and the extent of interaction of these fluids with other fluids in the wider hydrogeological system. The large range in thermal maturity exhibited across the basin, as demonstrated by the range in δ13C of methane from −37.8 to −47.5‰ VPDB, allows us to constrain the evolution of the noble gas signature within a source-rock during hydrocarbon generation and expulsion. For the first time, we show that 36Ar concentrations in hydrocarbon gases are not simply controlled by solubility exchange with formation water. Instead, they are shown to decrease dramatically (from 2.6 × 10−7 to 7.0 × 10−9 cm3STPcm−3) with increasing thermal maturity, which we attribute to a dilution effect as more short-chain hydrocarbon compounds are generated through cracking of kerogen and secondary cracking of oil. We develop a model that combines 36Ar concentrations with δ13C data in order to quantify the retention capacity for generated hydrocarbons, and show that between 40 and 80% of the hydrocarbons generated by the Eagle Ford shale are retained within the formation. We also calculate that radiogenic 4He concentrations within the Eagle Ford are well in excess of that which could have accumulated internally since deposition and requires contributions from external 4He sources. The identification of both hydrocarbon expulsion and helium addition to nominally ‘tight’ formations now provides a process driven and quantitative understanding of the fluid migration dynamics and processes controlling these critical formations.

Characteristics of source rock controlling hydrocarbon distribution in Huizhou Depression of Pearl River Mouth Basin, South China Sea

In a petroleum accumulation system, the source rock plays a significant geological role in controlling hydrocarbon distribution, because it provides the material basis for hydrocarbon accumulation. Thus, quantitative evaluations of source rock control on hydrocarbon distribution are useful for predicting future hydrocarbon discoveries. Using the Huizhou Depression in the Pearl River Mouth Basin, China, as a case study, geostatistical methods and probability calculation were employed to analyze the controlling effect of source rocks. The Huizhou Depression can be divided into five petroleum accumulation systems of which the Huixi contains the largest known amount of hydrocarbons. A probability model of hydrocarbon accumulations is established for quantitative evaluation of potentially favourable hydrocarbon distribution. In each petroleum accumulation system, the larger the hydrocarbon expulsion intensity, the larger the amount of hydrocarbons that accumulates; the longer the distance from the hydrocarbon expulsion centre, the lower the amount of hydrocarbon accumulates. The hydrocarbon distribution limit controlled by the source rock is 3.5 times the radius of the source kitchen in the Huizhou Depression. In the current state of exploration, oil fields in the Huizhou Depression are mainly observed in the areas 1.5 to 2 times the source kitchen radius. Based on the prediction model, structural highs around hydrocarbon source kitchens are potentially favourable zones for structural hydrocarbon reservoirs, and the interiors of source kitchens are potentially targets for subtle hydrocarbon reservoirs and unconventional resources.

The hydrocarbon generation potential and migration in an alkaline evaporite basin: The Early Permian Fengcheng Formation in the Junggar Basin, northwestern China

Abstract The Permian Fengcheng Formation in the Mahu Sag in the Junggar Basin represents deposition in a rare alkaline saline lake, with hydrologically closed conditions, alkaline saline brines, and intense volcanic activity. The Fengcheng Formation contains large volumes of high-quality source rocks, which form not only in the depocenter but also in the wide, shallow lake margins. The source rocks analyzed in this study are different from those in most other ancient lakes in the following aspects: genesis and occurrence of organic matter, kerogen type, lithological composition, and hydrocarbon migration pathway. This study showed that the Fengcheng Formation has high hydrocarbon generation potential and that combinations of multiple paths enhanced the hydrocarbon expulsion and migration. Benthic microbial mats and algae that bloomed in the alkaline saline lake represent the dominant types of organic matter. Due to their specific composition, the evaporites may have catalyzed hydrocarbon generation via organic-inorganic interactions, while intergranular seams in bedded/laminated evaporites provided paths for hydrocarbon migration. Stylolites, with high contents of brittle minerals and low clay content, also allowed favorable paths for hydrocarbon expulsion and migration. Combining hydrocarbon expulsion fractures in the organic-rich laminae, fractures and microfractures caused by compressive tectonic stress, pathway networks formed that enhanced the efficiencies of both hydrocarbon expulsion and migration.

Quick Evaluation of Present‐Day Low‐Total Organic Carbon Carbonate Source Rocks from Rock‐Eval Data: Middle–Upper Ordovician in the Tabei Uplift, Tarim Basin

AbstractPrevious studies have postulated the contribution of present‐day low‐total organic carbon (TOC) marine carbonate source rocks to oil accumulations in the Tabei Uplift, Tarim Basin, China. However, not all present‐day low‐TOC carbonates have generated and expelled hydrocarbons; therefore, to distinguish the source rocks that have already expelled sufficient hydrocarbons from those not expelled hydrocarbons, is crucial in source rock evaluation and resource assessment in the Tabei Uplift. Mass balance can be used to identify modern low‐TOC carbonates resulting from hydrocarbon expulsion. However, the process is quite complicated, requiring many parameters and coefficients and thus also a massive data source. In this paper, we provide a quick and cost effective method for identifying carbonate source rock with present‐day low TOC, using widely available Rock‐Eval data. First, we identify present‐day low‐TOC carbonate source rocks in typical wells according to the mass balance approach. Second, we build an optimal model to evaluate source rocks from the analysis of the rocks' characteristics and their influencing factors, reported as positive or negative values of a dimensionless index of Rock‐Eval data (IR). Positive IR corresponds to those samples which have expelled hydrocarbons. The optimal model optimizes complicated calculations and simulation processes; thus it could be widely applicable and competitive in the evaluation of present‐day low TOC carbonates. By applying the model to the Rock‐Eval dataset of the Tabei Uplift, we identify present‐day low‐TOC carbonate source rocks and primarily evaluate the contribution equivalent of 11.87×109 t oil.

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.

Characteristics and distribution of continental tight oil in China

Tight oil in China is mainly distributed in Mesozoic-Cenozoic continental petroliferous basins, either generally occurs in tight sandstone or tight carbonate reservoirs which are paragenetic to or in contact with lacustrine petroleum source rocks. By the end of 2016, the continental tight oil in China has established an annual production capacity of 1.55 million tons, and a cumulative oil production of 2.52 million tons. In 2016, the continental tight oil production in China was about 800,000 tons. By analyzing the characterization of the tight oil in Ordos Basin, Songliao Basin, Jungar Basin, the organic-rich shale in China were formed in multiple geological periods including the Permian, Triassic, Jurassic, Cretaceous, Neogene, and Paleogene, in freshwater, semi-saline to hyper-saline lacustrine depositional setting. They are generally tens of meters to several hundreds of meters thick, have total organic carbon (TOC) contents of 0.4–16%, and thermal maturity of 0.4–1.4%. Algal bloom as results of volcanism, low sedimentation rate, transgression, and stratification of water body are prominent factors controlling the formation of organic-rich shales. Tight oil reservoirs in China mainly include tight sandstone, tight carbonate rock, tight sedimentary tuff, etc., all of which are characterized by strong heterogeneity and poor petrophysical properties, with in situ porosity and permeability generally no more 12% and 1 × 10−3 μm2 respectively. They are also characterized by tight pore-throat systems of nano- to micro-scales, with pore throat diameters in the range of 80–1800 nm, and complex pore structures. The producing reservoirs have pressure coefficients between 0.7 and 1.8, covering under-pressure to over-pressure. Crude oil properties vary greatly with densities ranging from 0.75 to 0.92 g/cm3. It is believed that the abundance and effectiveness of hydrocarbon supply controls the formation of oil saturation, and tight oil “sweet spots” are generally in or near the areas with high hydrocarbon expulsion intensities. In addition, the quality of the source rock and the type of source reservoir control the distribution of the “sweet spots”, and storage space and movable fluid guarantee the formation of the “sweet spot” area of high oil saturation. “Sweet spots” are often developed in local mini-structural highs under a broad and gentle-sloped background. Continental tight oil in China has estimated geological resource of 14.66 × 109 tons with a technically recoverable resource of 1.45 × 109 tons. Tight oil is mainly distributed in Ordos Basin, Songliao Basin, Bohai Bay Basin, Junggar Basin, and Qaidam Basin, within the Mesozoic and Cenozoic formations. Overall China has a relatively large tight oil reserve and good exploration prospect.

The effect of pressure and hydrocarbon expulsion on hydrocarbon generation during pyrolyzing of continental type-III kerogen source rocks

In order to define the roles of water and lithostatic pressure in petroleum formation of continental type-III kerogen source rocks, semi-closed hydrous pyrolysis experiments were conducted under with 50–1200 bar water pressure and 125–2000 bar lithostatic pressure at 480 °C. Our results will be of great benefit to the exploration of shale gas and deep petroleum in China. Increasing water pressure from 50 to 325 bar did not affect the yields of gaseous hydrocarbons, oil and bitumen, but increasing water pressure leads the more oil and less gaseous hydrocarbons from continental type-III kerogen in the 325–1200 bar water pressure range under semi-closed conditions. The decreasing yields of gaseous hydrocarbons, dryness of gaseous hydrocarbons and primary hydrogen together confirm that increasing water pressure promotes the primary reaction but decreases the cracking rate of oil. The decreasing values of S2, HI and H/C in the pyrolysed samples confirm that high water pressure can increase the efficiency of hydrocarbon generation from continental type-III kerogen, while the maturation of kerogen correspondingly increases as shown by increasing values of VR and Tmax. In the 125–625 bar lithostatic pressure range, oil cracking and primary reaction of type-III kerogen may have contributed to the decreasing effect of hydrocarbon expulsion. The increasing hydrogen and gaseous hydrocarbon yields also confirm that the cracking of oil is enhanced within this pressure range. The decreasing trends of oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was reduced by the high lithostatic pressure in the 625–2000 bar pressure range. The increasing values of S2, HI and H/C, and decreasing values of VR and Tmax of pyrolysed samples confirm the retardation effect of highlithostatic pressure on the efficiency of hydrocarbon generation and maturation. In addition, the results also indicate that expelling hydrocarbons strongly promotes further hydrocarbon generation and retards the cracking of oil from continental type-III kerogen in source rocks.

3D BASIN MODELLING OF OLIGOCENE – MIOCENE MAIKOP SOURCE ROCKS OFFSHORE ROMANIA AND IN THE WESTERN BLACK SEA

Hydrocarbon discoveries in the Western Black Sea have proved the presence of both thermogenic and biogenic petroleum systems. The presence of Tertiary biomarkers in oils from the Romanian part of the Western Black Sea sub‐basin, and correlation with Oligocene to Lower Miocene black shales, suggests that the thermogenic petroleum system is sourced mainly by the Oligocene – Miocene Maikop Group. Older source rocks may also be present locally in other parts of the sub‐basin, but their contribution is currently poorly understood.This paper presents the results of 3D basin modelling which was intended to evaluate charge models for prospects in the Western Black Sea sourced by the Maikop Group shales. The model is built on the regional‐scale interpretation of recently acquired, long‐offset 2D reflection seismic data, and was calibrated with proprietary and published well, geochemical and temperature data. The sensitivity of the thermal models on source maturity was tested. The basin models investigated two end‐member heat‐flow scenarios, “hot” and “cold”. Whereas the “hot” model more successfully reproduces the field and well data in shelfal areas of the Western Black Sea, the “cold” model is considered to be more valid for deeper‐water areas. Hydrocarbon expulsion maps were calculated for both scenarios at key stratigraphic levels, with preferential migration routes identified.The results of the basin modelling suggest that the most likely source rocks for the oils in accumulations offshore Romania are located in the mid‐Maikop Group (Upper Rupelian? to Chattian). Core data from offshore wells indicate that the source rocks consist of black shales with fair to good oil generation potential (TOC ∼ 0.5 to 4.5%, HI <600 mg/g TOC, and mixed Type II/III kerogen). At the present day, these shales are in the early oil window offshore Romania to the SE of the producing fields, and in the wet gas window further to the east. Hydrocarbon expulsion from the mid‐Maikop interval began during the Middle Miocene, but significant volumes of liquids were generated only in the Late Miocene with the peak of expulsion not yet reached. Charging the accumulations on the Romanian Shelf requires lateral migration along the base‐Oligocene unconformity over distances of about 20–50 km. In addition, hydrocarbons have charged underlying Eocene and Cretaceous reservoir sections by lateral downward migration, filling structural traps and spilling over to higher structural levels. The results highlight the underexplored potential associated with the Maikop Group in the Western Black Sea.

Deep-Lacustrine Shale Heterogeneity and Its Impact on Hydrocarbon Generation, Expulsion, and Retention: A Case Study from the Upper Triassic Yanchang Formation, Ordos Basin, China

The Chang-7 shale of the Upper Triassic Yanchang Formation was deposited in a deep-lacustrine environment in the southwest part of the Ordos Basin. It is characterized by a strong lithological heterogeneity, consisting primarily of pure shale and sandy laminated shale. This study explored the impact of sandy laminae in the thick pure shale on hydrocarbon generation, retention, and expulsion, which were rarely considered in previous studies. Based on core observation, thin section, and geochemical analysis, the hydrocarbon generation, retention, and expulsion characteristics were obtained for both pure shale and sandy laminated shale. In general, the Chang-7 shale stays at low mature to mature thermal evolution stage and has good hydrocarbon generation potential. It contains mainly Type II kerogen with an average total organic carbon (TOC) of 2.9% and average (S1 + S2) of 8.2 mg/g. Compared with sandy laminated shale, pure shale contains more retained liquid hydrocarbon and has a higher amount of asphaltene and nitrogen–sulfur–oxygen (NSO) polarized components, indicating a relatively weak hydrocarbon expulsion process. The middle part of a thick pure shale retains more liquid hydrocarbon and has higher percentages of asphaltene and NSO polarized components than that of the top and basal part of the shale where sandy laminae occur. The difference in hydrocarbon retention capacity is interpreted to have been primarily caused by the comparatively higher reservoir quality of the sandy laminated shale, having higher amount of brittle minerals and larger pores than the pure shale. Polymer dissolution and nanopore adsorption are also key factors in hydrocarbon retention and component partition. Based on this study, we suggest that sandy laminated shale, which receives most of the hydrocarbon from adjacent pure shale, should be the current favorable shale oil exploration targets. Even though pure shale contains high hydrocarbon potential, its development is still pending improved technologies, which could solve the challenges caused by complicated geological conditions.

Modeling of the whole hydrocarbon-generating process of sapropelic source rock

Based on experimental data from hydrocarbon generation with a semi-open system, hydrocarbon generation kinetics modeling in gold tube of closed system, high temperature pyrolysis chromatography mass spectrometry experiment with open system and geological data, the characteristics of whole hydrocarbon-generating process, hydrocarbon expulsion efficiency and retained hydrocarbon quantity, origins of natural gas generated in high-over mature stage and cracking temperature of methane homologs were investigated in this study. The sapropelic source rock has a hydrocarbon expulsion efficiency of 30%−60% and 60%−80% in the major oil generation window (with Ro of 0.8%−1.3%) and high maturity stage (with Ro of 1.3%−2.0%) respectively; and the contribution ratio of kerogen degradation gas to oil cracking gas in total generated gas in high maturity stage is about 1:4. The degradation gas of kerogen accounts for 20%, the retained liquid hydrocarbon cracking gas accounts for 13.5%, and the amount of out-reservoir oil cracking gas (including aggregation type and dispersed oil cracking gas) accounts for 66.5%. The lower limit of gas cracking is determined preliminarily. Based on the new understandings, a model of the whole hydrocarbon-generating process of source rock is built.

Heterogeneity of organic-rich lacustrine marlstone succession and their controls to petroleum expulsion, retention, and migration: A case study in the Shulu Sag, Bohai Bay Basin, China

Abstract We documented a new type of self-sourced unconventional reservoir consisting of interbedded organic-rich marlstone and calcareous conglomerates developed in lacustrine carbonate successions in the Eogene Shahejie formation (Es33) of Shulu Sag, Bohai Bay Basin. The Es33 interval used to be regarded as a set of homogeneous source rock for oil plays in the upper strata due to their high abundance of organic-matter. However, the Es33 interval actually has very strong heterogeneity in their organic richness and hydrocarbon generation ability among different stratigraphic sequences (the Es33 interval can be divided into sequence SQ1 to SQ5 from bottom to up). To better understand the heterogeneity in the unconventional reservoir and its effect on the hydrocarbon retention and migration, thin sections and scanning electronic microscopes were used to characterize the pore system in the reservoir, together with a amount of collected well database including wireline logging, gas logging, and physical property data (e.g. porosity and permeability). Intensive sampling from the Es33 interval of Well ST1H was performed and samples were measured with Rock-Eval and TOC analysis. The rock extracts were analyzed with SARA and gas chromatography - Mass spectrum (GC-MS) analysis to examine the fluid geochemical characteristics and molecular biomarkers composition. The results show that although the whole Es33 are characterized by low and ultra-low porosity and permeability, but the pore types in different lithology are different. The organic-rich marlstones develop large amount of organic matter pore and dissolved mineral pores, while the conglomerates developed inter-partical or inter-crystalline mineral pores dominantly. The sequence SQ2 has high quality of source rock for hydrocarbon generation, possessing moderate to high content of organic matter (TOC range 2–5 wt %) with Type I-II kerogen predominantly, basically in the thermal maturity stage of the peak oil window. OM and lithology play significant roles in controlling hydrocarbon expulsion and retention. Oil retained in the organic-rich marlstone was observed to absorb on the surface of OM and clay-rich matrix, which is also supported by the positive correlation between retained oil (represented by Rock-Eval S1) and TOC. Organic-lean conglomerates in the sequence SQ3 obtain abnormal high content of low mature oil determined by biomarker composition, which suggests the oil were derived from oil migration and mixture. Thermal maturity profile based on hydrocarbon biomarkers composition of rock extract provides a method to determine the effect of the hydrocarbon migration or retention within source rock. The organic-lean intervals adjacent or close to organic-rich source rock can be favorable targets for oil exploration.

Tracing enhanced oil recovery signatures in casing gases from the Lost Hills oil field using noble gases

Enhanced oil recovery (EOR) and hydraulic fracturing practices are commonly used methods to improve hydrocarbon extraction efficiency; however, the environmental effects of such practices remain poorly understood. EOR is particularly prevalent in oil fields throughout California where water resources are in high demand and the disposal of large volumes of produced water may affect groundwater quality. Consequently, it is essential to better understand the fate of injected (EOR) fluids in California, and other subsurface petroleum systems, as well as any potential effect on nearby aquifer systems. Noble gases can be used as tracers to understand hydrocarbon generation, migration, and storage conditions, as well as the relative proportions of oil and water present in the subsurface. In addition, a noble gas signature diagnostic of injected (EOR) fluids can be readily identified. We report noble gas isotope and concentration data in casing gases from oil production wells in the Lost Hills oil field, northwest of Bakersfield, California, and injectate gas data from the Fruitvale oil field, located within the city of Bakersfield. Casing and injectate gas data are used to: 1) establish pristine hydrocarbon noble-gas signatures and the processes controlling noble gas distributions, 2) characterize the noble gas signature of injectate fluids, 3) trace injectate fluids in the subsurface, and 4) construct a model to estimate EOR efficiency. Noble gas results range from pristine to significantly modified by EOR, and can be best explained using a solubility exchange model between oil and connate/formation fluids, followed by gas exsolution upon production. This model is sensitive to oil–water interaction during hydrocarbon expulsion, migration, and storage at reservoir conditions, as well as any subsequent modification by EOR.

Joint geophysical and geochemical evaluation of source rocks – A case study in Sayun-Masila basin, Yemen

Integration of geophysical and geochemical approaches is used for qualitative and quantitative evaluation of source rocks. The Upper Jurassic rocks in the Sayun-Masila basin are used as a case study due to its high hydrocarbon potentiality. Stratigraphically, these rocks could be differentiated from base to top into: Shuqra, Madbi and Nayfa formations. The total organic carbon (TOC) values were determined in the shale and/or carbonate intervals of these formations from four studied wells by the ΔlogR method using sonic, resistivity and gamma-ray log data. Then the discriminant analysis was applied in differentiating source from non-source rocks. Also, the effect of the burial and thermal histories on the organic material maturation and the oil and/or gas generation was studied through the application of two analytical methods, namely, the level of organic metamorphism (LOM) and the time-temperature index (TTI), depending on the corrected temperature logs integrated with the time and depth data. The reliability of the obtained results has been confirmed and combined with the results supplied from geochemical analyses. The Upper Jurassic sediments are found to be oil–prone source rock in a mature stage. The Madbi Formation is considered as the most effective source rock. The burial and thermal histories of the basin in four modeled wells showed that mature oil generation window and hydrocarbon expulsion would have been initiated in the depocenters from Upper Jurassic Madbi Formation source rock during Late Cretaceous to Middle Miocene time.

Diagenetic variation at the lamina scale in lacustrine organic-rich shales: Implications for hydrocarbon migration and accumulation

Lacustrine carbonate-rich shales are well developed within the Mesozoic-Cenozoic strata of the Bohai Bay Basin (BBB) of eastern China and across southeast Asia. Developing an understanding of the diagenesis of these shales is essential to research on mass balance, diagenetic fluid transport and exchange, and organic-inorganic interactions in black shales. This study investigates the origin and distribution of authigenic minerals and their diagenetic characteristics, processes, and pathways at the scale of lacustrine laminae within the Es4s-Es3x shale sequence of the BBB. The research presented in this study is based on thin sections, field emission scanning electron microscope (FESEM) and SEM-catholuminescence (CL) observations of well core samples combined with the use of X-ray diffraction (XRD), energy dispersive spectroscopy, electron microprobe analysis, and carbon and oxygen isotope analyses performed using a laser microprobe mass spectrometer. The dominant lithofacies within the Es4s-Es3x sequence are a laminated calcareous shale (LCS-1) and a laminated clay shale (LCS-2). The results of this study show that calcite recrystallization1 is the overarching diagenetic process affecting the LCS-1, related to acid generation from organic matter (OM) thermal evolution. This evolutionary transition is the key factor driving the diagenesis of this lithofacies, while the transformation of clay minerals is the main diagenetic attribute of the LCS-2. Diagenetic differences occur within different laminae and at variable locations within the same lamina level, controlled by variations in mineral composition and the properties of laminae interfaces. The diagenetic fluid migration scale is vertical and responses (dissolution and replacement) are limited to individual laminae, between zero and 100 μm in width. In contrast, the dominant migration pathway for diagenetic fluid is lateral, along the abrupt interfaces between laminae boundaries, which leads to the vertical transmission of diagenetic responses. The recrystallization boundaries between calcite laminae act as the main migration pathways for the expulsion of hydrocarbons from these carbonate-rich lacustrine shales. However, because the interaction between diagenetic fluids and the shales themselves is limited to the scale of individual lamina, this system is normally closed. The occurrence of abnormal pressure fractures can open the diagenetic system, however, and cause interactions to occur throughout laminae; in particular, the closed-open (C–O) diagenetic process at this scale is critical to this shale interval. Multi-scale C–O systems are ubiquitous and episodic ranging from the scale of laminae to the whole basin. Observations show that such small-scale systems are often superimposed onto larger ones to constitute the complex diagenetic system seen within the BBB combining fluid transport, material and energy exchange, and solid-liquid and organic-inorganic interactions.

A REVIEW OF THE COALY SOURCE ROCKS AND GENERATED PETROLEUMS IN THE DANISH NORTH SEA: AN UNDEREXPLORED MIDDLE JURASSIC PETROLEUM SYSTEM?

This paper reviews the Middle Jurassic petroleum system in the Danish Central Graben with a focus on source rock quality, fluid compositions and distributions, and the maturation and generation history. The North Sea including the Danish Central Graben is a mature oil province where the primary source rock is composed of Upper Jurassic – lowermost Cretaceous marine shales. Most of the shale‐sourced structures have been drilled and, to accommodate continued value creation, additional exploration opportunities are increasingly considered in E&P strategies. Triassic and Jurassic sandstone plays charged from coaly Middle Jurassic source rocks have proven to be economically viable in the North Sea. In the Danish‐Norwegian Søgne Basin, coal‐derived gas/condensate is produced from the Harald and Trym fields and oil from the Lulita field; the giant Culzean gas‐condensate field is under development in the UK Central North Sea; and in the Norwegian South Viking Graben, coal‐derived gas and gas‐condensate occur in several fields. The coaly source rock of the Middle Jurassic petroleum system in the greater North Sea is included in the Bryne/Lulu Formations (in Denmark), the Pentland Formation (in the UK), and the Sleipner and Hugin Formations in Norway. In the Danish Central Graben, the coal‐bearing unit is composed of coals, coaly shales and carbonaceous shales, has a regional distribution and can be mapped seismically as the ‘Coal Marker’. The coaly source rocks are primarily gas‐prone but the coals have an average Hydrogen Index value of c. 280 mg HC/g TOC and values above 300 mg HC/g TOC are not uncommon, which underpins the coals' capacity to generate liquid hydrocarbons (condensate and oil). The coal‐sourced liquids are differentiated from the common marine‐sourced oils by characteristic biomarker and isotope compositions, and in the Danish Central Graben are grouped into specific oil families composed of coal‐sourced oil and mixed oils with a significant coaly contribution. Similarly, the coal‐sourced gases are recognized by a normally heavier isotope signature and a relatively high dryness coefficient compared to oil‐associated gas derived from marine shales. The coal‐derived and mixed coaly gases are likewise assigned to well‐defined gas families. Coal‐derived liquids and gas discoveries and shows in Middle Jurassic strata suggest that the coaly Middle Jurassic petroleum system has a regional distribution. A 3D petroleum systems model was constructed covering the Danish Central Graben. The model shows that present‐day temperatures for the Middle Jurassic coal source rock ('Coal Marker') are relatively high (>150 °C) throughout most of the Danish Central Graben, and expulsion of hydrocarbons from the ‘Coal Marker’ was initiated in Late Jurassic time in the deep Tail End Graben. In the Cretaceous, the area of mature coaly source rocks expanded, and at present day nearly the whole area is mature. Hydrocarbon expulsion rates were low in the Paleocene to Late Oligocene, followed by significant expulsion in the Miocene up to the present day. High Middle Jurassic reservoir temperatures prevent biodegradation.

Geochemical characteristics of the Triassic Chang 7 lacustrine source rocks, Ordos Basin, China: Implications for paleoenvironment, petroleum potential and tight oil occurrence

The fact that high-quality lacustrine source rocks (generally shale and mudstone) control the formation and distribution of conventional and unconventional oil and gas reservoirs in lacustrine basins has been well-accepted in petroleum exploration and exploitation. Taking the Chang 7 lacustrine source rocks in the Ordos Basin as an example, several points having been reached are as follows. (1) The Chang 7 source rocks possess an excellent source rock potential, and the shales hold a better potential than the mudstones. (2) The paleoenvironments of the Chang 7 source rocks were sub-reducing to sub-oxidizing conditions and fresh- and brackish-water depositional environments with a maximum water depth of 150 m. The organic matter origins of the source rocks are mainly plankton, algae, bacteria and other aquatic microorganisms. (3) The beginning time of the oil generation of the Chang 7 source rocks is at 165 Ma, and the peak oil generation occurred during 115–95 Ma. The cumulative amounts of oil generation are up to 4711 × 103 t/km2 and the ratios of peak generation amounts to cumulative generation amounts are >50%. The beginning timing and peak generation timing of the shales are earlier than those of the mudstones, respectively, and the cumulative oil generation amount of the shales is higher than that of the mudstones, indicating a better oil generation potential of the shales. (4) Due to the more remained oil possessed in the shales, the hydrocarbon expulsion threshold of the Chang 7 shales (2560 m) is deeper than that of the Chang 7 mudstones (2080 m). (5) The occurrences of the Chang 8–6 tight oils are predominantly controlled by the outer boundary of the Chang 7 source rocks distribution, while the transition areas between thickness, TOC, and RO high value centers are the accumulation and enrichment zones. The Chang 7 shales controlled the occurrence of the Chang 8 tight oil reservoirs and the Chang 7 mudstones controlled the occurrence of the Chang 7 and Chang 6 tight oil reservoirs.