Marine Shale Research Articles

Assessment of terrigenous and marine sourced oils mixtures: Los Manueles field, Maracaibo basin Venezuela

Seven crude oil samples from Los Manueles field, Maracaibo Basin, Venezuela, were analyzed to evaluate oil mixtures associated with different oil charges into the reservoirs. Analyses of the bulk physicochemical parameters suggest variations in the API gravity, the concentration of saturated and aromatic hydrocarbons, NSO compounds + asphaltenes, sulfur, vanadium, nickel, and the biomarkers distribution. The oils were divided in two groups: G-I with high saturated hydrocarbons and low NSO compounds + asphaltenes, sulfur, vanadium and nickel, a bimodal distribution of n-alkanes, high Pr/Ph and oleanane index, low steranes index, low abundance of tricyclic terpanes and C35S/C34S < 0.54 and G-II with low saturated hydrocarbons and high NSO compounds+ asphaltenes, sulfur, vanadium and nickel, an unimodal distribution of n-alkanes with low Pr/Ph and oleanane index, high steranes index, abundance of tricyclic terpanes and C35S/C34S > 0.70. G-I has a higher contribution of terrigenous organic matter compared to G-II, characterized by a higher contribution of marine organic matter. Source rock lithology biomarker indicators suggest marine shale as the source rock for oils of terrigenous origin. The results indicate that oils were generated by two independent source rocks, La Luna Formation and a secondary source rock with terrigenous organic matter, probably represented by the Capacho Formation.

Well-logging evaluation of the shale gas potential in the lower Silurian Longmaxi Formation, Weiyuan, southern Sichuan Basin, China

Recent observations of shale gas breakthroughs in the Weiyuan marine shale gas play in the Sichuan Basin have attracted great interest. To better understand these breakthroughs, we have used core description, cyro-focused ion beam scanning electron microscopy data, X-ray diffraction data, organic geochemistry, and well-logging data to better understand the reservoir characteristics carbonaceous shale, calcareous shale, and siliceous shale lithology, with a focus on organic-rich shale units. We find that conventional well-log methods are effective in mapping the spatial distribution of organic-rich shale in the Weiyuan area where the total organic carbon (TOC) content in the Longmaxi Formation ranges from 1.35% to 6.95%, averaging 4.42%. The kerogen is type I-II, and the vitrinite reflectance (Ro) is greater than 2.57%, which indicates that the formation is susceptible to shale gas accumulation. The clay mineral content ranges from 48 to 63 wt% (avg. 51 wt%) with illite and chlorite averaging 73.8% and 25.7%, respectively. The brittle mineral quartz and plagioclase content ranges from 32 to 61 wt% (avg. 47 wt%). Compared to the surrounding lithologic units, the marine shale exhibits relatively high gamma ray, neutron, sonic, resistivity, potassium, and uranium (U) values and relatively low density, photoelectric effect, and thorium/U values, allowing us to construct crossplots to define the units of interest. Using the same process, we quantify the TOC content providing a spatial distribution of organic-rich shale using conventional well logging.

Pore Structure and Fractal Characteristics of Continental Low Maturity Organic-Rich Shale in the Sha-4 Member of the Liaohe Western Depression

The research on pore structure and heterogeneity of shale reservoirs has always been a hotspot in the study of unconventional reservoir characteristics. China is a country dominated by continental shale. Compared with marine shale, continental shale has lower maturity and stronger reservoir heterogeneity. In this study, Sha-4 shale in the Liaohe Western Depression was selected for low-temperature nitrogen adsorption, scanning electron microscopy and other experiments revealing the pore structure and fractal characteristics of continental low mature organic-rich shale. The fractal dimension was calculated by the FHH model and the effects of TOC and mineral composition on pore structure and fractal characteristics were discussed. The results show that the Sha-4 shale in the study area is mainly mesoporous and the main pore types are inorganic pores with relatively large pore diameters, such as intergranular pores and inter-crystalline pores. The pore morphology is very complex, mainly narrow slit and flat pore, and the pore is often filled with organic matter. The fractal dimensions D1 range from 2.58 to 2.87 and D2 range from 2.18 to 2.55, and the pore structure shows obvious dual fractal characteristics. The pore structure and fractal characteristics of shale are mainly affected by TOC and quartz due to the low degree of the thermal evolution of shale and their effects are different from those of marine shale reservoirs. The increase in TOC reduces the heterogeneity of the shale reservoir. In addition, mineral particles with strong weathering resistance and stability such as quartz can protect the pore structure of shale, improve the pore structure and reduce the reservoir heterogeneity. This study can provide support for the study of low maturity continental shale reservoir heterogeneity in the Sha-4 member of the Liaohe Western Depression.

GEOCHEMICAL CHARACTERISTICS OF CRUDE OILS FROM THE SHARARA‐C OIL FIELD, MURZUQ BASIN, SOUTHWESTERN LIBYA

Crude oil samples from the Sharara‐C oil field (Concession NC‐115, Murzuq Basin, SW Libya) were analysed by organic geochemical methods in order to infer the geochemical characteristics of their respective source rocks. Aromatic hydrocarbons were analysed by gas chromatography – mass spectrometry (GC‐MS), and gas chromatography – tandem mass spectrometry (GC‐MS‐MS) was used to analyse saturated biomarkers. The Sharara‐C oils are interpreted to have been generated by marine shales containing mixed terrigenous and marine organic materials deposited in an intermediate (suboxic) environment. Age‐specific biomarker ratios indicated that the oils are older than Cretaceous, and maturation‐related parameters pointed to their high thermal maturity. Consistent with previous studies, source rocks are inferred to be “hot” shales in the Lower Silurian Tanezzuft Formation.Almost all the parameter ratios calculated varied over a very narrow range, indicating that the investigated oils were compositionally similar. The only significant difference that was noted concerned the sterane/hopane ratios whose variation suggested that there was some variability in the composition of the source organic material.The organic geochemical parameters determined for the Sharara‐C crude oils were compared with published data on other crude oils from Concession NC‐115. Almost all the parameters agreed well with previously published data on oils from this part of the Murzuq Basin. The greatest deviation concerned the values of some of the maturity parameters. This tended to confirm the conclusions of previous studies concerning the presence of a number of distinct oil families and sub‐families in the Sharara oil field area which are genetically related but which have different maturities.

Study on Pyrolysis Hydrocarbon Generation Kinetics and Shale Gas Formation Process of Marine Continental Transitional Rocks in Shanxi Formation, Ordos Basin

The marine continental transitional facies shale of Shan23 sub member of Shanxi Formation in Ordos Basin was selected, and the hydrocarbon generation kinetics of Shan 23 sub member marine continental transitional facies shale was studied through open system thermal simulation experiment. The experimental results show that the pre exponential factor of Shan 23 shale is 12.92*1015/s, and the activation energy is mainly concentrated in 52~82kcal/mole. On this basis, combined with petromod basin simulation software, the burial history, thermal evolution history and hydrocarbon generation history of Shanxi Formation shale are established, and the formation process of shale gas is clarified. Finally, using the genetic method, combined with the original TOC restored by Petromod basin simulation software and the hydrocarbon generation obtained from the open system thermal simulation experiment, the resources of the study area are calculated when the hydrocarbon expulsion efficiency is 50%. The calculation results show that the shale gas resource in the study area is 12.41*1012m3, which shows a good exploration potential of sea land transitional facies shale in the study area.

Comprehensive Experimental Study on the Gas Breakthrough Pressure and Its Implication for the Reservoir Performance

Abstract It is challenging to interpret the gas breakthrough mechanisms, controlling factors, and its relationships with the reservoir parameters for unconventional reservoirs such as the gas shale, due to the accumulation characteristics of source-reservoir integration. Take the typical marine shale gas of the B field for example, we use the step-by-step (SBS) test to measure the gas breakthrough pressure of the water saturated shales, and investigate the influential factors such as the pore size distribution, mineral composition, and organic geochemical properties. Moreover, the implication of the gas breakthrough capability for the reservoir quality such as the porosity, permeability, the gas content, and the gas occurrence state are addressed. Based on our work, it is observed that the gas breakthrough capability in shale is influenced by many factors. Generally, the gas breakthrough pressure is positively with the amount of ductile minerals such as the clay and the plagioclase, but negatively with the amount of brittle minerals such as the quartz. In addition, the gas breakthrough pressure is decreased with the increase of the pore radius and the specific surface areas. What is more, the influences of geochemical properties on the gas breakthrough capability should not be neglected. Due to the development of organic pores in the kerogen, the gas breakthrough pressure is found to decrease with the increase of the total organic carbon content (TOC) and the residual carbon content (RC). The breakthrough pressure can be used as the significant parameter to indicate the reservoir quality of the shale gas. It is shown that the breakthrough pressure is inversely with the porosity, permeability, the total gas content, and the adsorbed gas content. It is practical and meaningful to measure and estimate the breakthrough pressure for the formation evaluation in shale gas reservoirs.

Insight into Water Occurrence and Pore Size Distribution by Nuclear Magnetic Resonance in Marine Shale Reservoirs, Southern China

The exploitation of shale gas has been a hot topic, and the understanding of water occurrence and pore size distribution in shale reservoirs plays a crucial role in efficiently developing this type of resource. In this study, we target moderate-shallow marine shales from the Lower Cambrian Niutitang Formation and deep marine shales from the Lower Silurian Longmaxi Formation. Low-field nuclear magnetic resonance is applied to investigate the water occurrence and pore size distribution together with complementary experiments including mineral component analysis, scanning electron microscopy (SEM), contact angle measurement, and high-speed centrifugation. The SEM analysis shows that the moderate-shallow shales have some inorganic nanopores and cracks but almost no organic pores, while the deep shales have abundant organic nanopores. The average movable water saturation of moderate-shallow and deep shales is only 15.5% and 15.2%, respectively. It implies that the high irreducible water saturation is a typical characteristic for both marine shales, which is ascribed to the strong capillary force of the nanopore inhibiting water flowing out of the pore space. By means of high-speed centrifugation and contact angle measurement, the converting factor of the T2 value into pore size was obtained. The average pore size in moderate-shallow shales is 19.4, 21.8, and 26.8 nm, respectively, while the average pore size in deep shales is 109, 57, and 68.4 nm, respectively, for the tested samples. This indicates that organic pores in deep shales contribute to the development of abundant nanopores. This study brings insight into characterizing the water occurrence and pore size distribution of moderate-shallow and deep marine shales.

Lithofacies and pore features of marine-continental transitional shale and gas enrichment conditions of favorable lithofacies: A case study of Permian Longtan Formation in the Lintanchang area, southeast of Sichuan Basin, SW China

In this work, the Permian Longtan marine-continental transitional shale in the southeast of Sichuan Basin was taken as study object. Through petrology and geochemical analysis, lithofacies types of the marine-continental transitional shale were classified, key controlling factors of physical properties and gas content of the different shale lithofacies were analyzed. The research results show that the Longtan Formation marine-continental transitional shale in the study area has four types of lithofacies, namely, organic-lean calcareous shale, organic-lean mixed shale, organic-lean argillaceous shale, and organic-rich argillaceous shale, among which the organic-rich argillaceous shale is the most favorable lithofacies of the study area. The pore types of different lithofacies vary significantly and the clay mineral-related pore is the dominant type of the pore system in the study area. The main controlling factor of the physical properties is clay mineral content, and the most important factor affecting gas content is TOC content. Compared with marine shale, the marine-continental transitional shale has low average values, wide distribution range, and strong heterogeneity in TOC content, porosity, and pore structure parameters, but still contains some favorable layers with high physical properties and gas contents. The organic-rich clay shale deposited in tidal flat-lagoon system is most likely to form shale gas sweet spots, so it should be paid more attention in shale gas exploration.

Sequence stratigraphic framework of the Rumaila and Mishrif Formations, onshore Kuwait

High-resolution biostratigraphic and paleoenvironmental investigations have been integrated with sedimentology and wireline log data to establish a biostratigraphically constrained depositional sequence stratigraphic framework. The Rumaila and Mishrif formations are early to middle Cenomanian to early Turonian in age. The Rumaila Formation was deposited in distal inner ramp to outer ramp settings. The Mishrif Formation was deposited in inner to middle ramp settings comprising transitional, tidal flats, lagoonal, shoal, backshoal and foreshoal sub-settings. The two formations are coincident with 3rd order depositional sequences K130 and K140. The K130 sequence boundary lies on the contact between the lagoonal, non-calcareous shale of the upper Ahmadi Formation and the carbonates and highly calcareous shale of the Rumaila Formation. The K130 transgressive systems tract is composed of a highly calcareous marine shale at the base of Rumaila Formation, which contains abundant to common nannofossils, common to rare foraminifera and ostracods. The K130 MFS is characterized by occurrence of abundant foraminifera and ostracods. The K130 highstand systems tract is comprised of interbeded mudstones, wackestones, packstones and dolomitic mudstone. The early highstand is fossiliferous, becoming progressively less fossiliferous in the late highstand. The K140 sequence boundary coincides with the Rumaila and Mishrif formational contact. The incremental increase in the abundance of deeper marine foraminiferal assemblages within the mudstone and wackestone interbeds overlying this contact indicates initiation of a marine transgressive event. A thin, regionally extensive, dark-grey, non-calcareous shale which is largely barren of microfossils and high gamma ray is considered a proxy of the global OAE 2 anoxic event of late Cenomanian to earliest Turonian age. The early highstand of K140 is composed of middle ramp mudstone to wackestone interbeds enriched in open marine planktonic and benthic foraminifera. The late highstand is represented by shoal, proximal shoal deposits enriched in coralline and rudist wackestone and packstone overlain by miliolid lagoonal wackestones underneath the K150 sequence boundary, known as pre-Aruma unconformity.

Occurrence and Migration Mechanisms of Methane in Marine Shale Reservoirs

The occurrence mechanism of methane is very important as evaluating the gas-bearing properties of marine shale reservoirs, and the evaluation of the development effect of shale gas wells need to focus on the migration mechanism of methane. In this study, LTNA technology and NMR technology were used to analyze the pores and methane of shale. The results show that inorganic pores have better connectivity, larger pore size, and micro–nano cracks between pores compared to organic pores. Most of the pores in shale are micropores and mesopores, which provide most of the specific surface area, but the contribution of macropores to pore volume cannot be ignored. Adsorbed gas volume depends on the pore surface area and gas pressure, while free gas volume depends on pore volume and gas pressure. The pore structure of micropores and mesopores is complex, and the specific surface area is large. The dispersion force between pore surface molecules and methane molecules is firm, which makes the pore wall an ideal enrichment space for adsorbed gas. Macropores have larger pore volumes and can store more free gas. In the process of gas well development, free gas is first discharged from pores under the action of the pressure gradient. As the pore pressure is lower than the critical desorption pressure, adsorbed gas begins to desorb in large quantities. It should be noted that the desorption process of adsorbed gas is slow and persistent, which makes it impossible for gas wells to achieve higher recovery in a shorter production cycle. Therefore, improving the recovery rate of adsorbed gas is the key to future research on shale gas development effects. This study is helpful in clarifying the occurrence and migration mechanism of methane in marine shale reservoirs and guiding the development of gas wells.

Insights into organic metagenesis using Raman spectroscopy and high resolution mass spectrometry: A case study of the Shahezi formation, deep Songliao basin, China

The maturity of sedimentary organic matter is a key parameter for evaluating oil and gas resources. Existing maturity indicators have different evaluation principles and application scopes. This study investigated samples of high to overmature lacustrine source rocks (Ro = 1.33%–4.24%) from the deep Shahezi formation in the Songliao basin, including the zone of catagenesis and metagenesis. Various methods, including vitrinite reflectance, Tmax, laser Raman spectroscopy, and Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) were used to evaluate the samples' maturity. Through laser Raman analysis of representative samples from the Shahezi formation, most laser Raman parameters showed an inflection point or reversal when the thermal evolution of deep source rocks in the Shahezi formation reaches a certain stage. The variation trend of some Raman parameters and Ro has strong regularity (1.33% < Ro < 3.52%). Based on FT-ICR MS, this research analyzed the relative content and molecular composition of polycyclic and heterocyclic aromatic compounds in soluble organic matter of lake source rock samples and comparison samples (marine shale). Quantitative maturity evaluation of organic matter was performed by converting the signal intensity of each compound. The fitting results of maturity parameter based on FT-ICR MS and Tmax indicated that the maturity parameter of the samples have high coefficient of correlations with maturity in the vitrinite reflectance (Ro) range of 1.33%–2.5% and the Tmax range of 420 °C–600 °C. The maturity parameter values decreased as Ro exceeded 2.5% and Tmax exceeded 600 °C. These findings are attributed to the thermal stability of organic compounds and the formation of pyrobitumen and graphite. The parameters of laser Raman spectroscopy also confirmed the growth of aromatic rings reflected by the maturity parameters of FT-ICR MS. These two methods revealed the structural changes of organic matter in the thermal evolution process from multiple perspectives and provided insights for the maturity evaluation of deep source rocks.

Microstructural Analysis of Organic-Rich Shales: Insights from an Electron Microscopic Study by Application of FIBSEM and TEM

Matrix-related pores play a significant role in controlling hydrocarbon production in organic-rich shales. Multiple matrix-related pore types of typical marine shales in the Sichuan Basin have been visually investigated and identified by transmission electron microscopy (TEM) on ultra-thin sections and by focused ion beam-scanning electron microscopy (FIBSEM) on polished sections. OM-hosted pores seem universal and range in sizes from below 1 nm to hundreds of nanometers and they are not homogeneously developed and distributed, which is mainly determined by thermal maturity and OM composition. Mineral-hosted pores are defined by mineral frameworks and occur in open spaces related to ductile or rigid grain fabric. The four porous mineral types that occur are clay intrapores, carbonate solvopores, pyrite interpores, and quartz interpores, and they range in size from less than 1 nm to more than several microns. Aggregate-hosted pores are predominantly associated with clay-organic aggregates, pyrite-organic aggregates, clay-pyrite aggregates, and clay-organic-pyrite aggregates. The most common aggregate-hosted pore networks are defined by clay-organic aggregates, and the pores are largely developed between the clay and organic layers and may be the important adsorption spaces for methane. Fracture-related pores include microchannels and microfractures of various sizes and shapes and they could play a key role in providing hydrocarbon migration pathways. FIBSEM and TEM show direct evidence that OM-hosted pores and fracture-related pores contribute more to the effective pore network and the excellent reservoir quality, whereas poor reservoir quality may come from aggregate-hosted pores.

Gas-Bearing Property in Deep Marine Shale and Its Micro Controlling Factors: Evidence from the Lower Silurian Longmaxi Formation in Southern Sichuan, China

Abstract The gas content in shale reservoirs is often determined by the micro storage and sealing capacities of the reservoir. Deep shale reservoirs are in the high- or over-thermale maturity stage and have complex pore structure and connectivity, which are highly heterogeneous in vertical distribution. Research on the gas-bearing property of deep shale reservoirs is limited by these complex microscopic conditions. To analyze the gas-bearing characteristics of deep shale reservoirs, this work collected and summarized data on total organic carbon content, mineral composition, porosity, water saturation, and gas content measured on-site for the Longmaxi Formation in the Sichuan Basin in southern Sichuan, China. Then, experimental methods, such as X-ray photoelectron spectroscopy, transmission electron microscope, low-pressure N2 adsorption, spontaneous imbibition, and high-pressure methane adsorption, were used to analyze the micro storage and sealing capacities of the deep shale reservoirs. The results show that, different from shallow shale reservoirs (&amp;lt;3500 m), deep shale reservoirs have a higher graphitization degree and water saturation. An abundance of graphite structures often leads to weak resistance of organic matter to compression, deformation, or even collapse of pores in organic matter and severe damage to the gas storage space. However, a higher degree of graphitization can enhance the ability of the shale reservoirs to adsorb gas and self-sealing. The high water saturation in the reservoirs can interact with clay minerals and negatively affect the gas accumulation, storage, and transmission capacities of the shale reservoirs. However, the upper shale reservoirs with higher water saturation can seal the lower shale reservoirs, helping it preserve shale gas. Based on the vertical distribution of graphite structure, clay minerals contents, lithofacies, and water content in deep shale reservoirs, the essential microscopic conditions for deep shale reservoirs to have high gas content were proposed. This paper provides a detailed explanation and evaluation of deep shale’s storage and sealing capacities at the microscopic scale and can serve as a reference for further identifying the patterns for high-yield and rich shale gas reservoirs and improving deep shale gas exploration technologies.

Reservoir Characteristics and Resource Potential of Marine Shale in South China: A Review

Many sets of Paleozoic marine organic-rich shale strata have developed in South China. However, the exploration and development results of these shale formations are quite different. Based on the data of core experiment analysis, drilling, fracturing test of typical wells, the reservoir differences and controlling factors of four sets of typical marine organic-rich shale in southern China are investigated. The four sets of shale have obvious differences in reservoir characteristics. Ordovician–Silurian shale mainly develops siliceous shale, mixed shale and argillaceous shale, with large pore diameter, high porosity, moderate thermal maturity, large pore volume and specific surface area. Cambrian shale mainly develops siliceous shale and mixed shale, with small pore diameter, low porosity, high thermal maturity and smaller pore volume and specific surface area than Ordovician–Silurian shale. Devonian–Carboniferous shale has similar mineral composition to Ordovician–Silurian shale, with small pore diameter, low porosity, moderate thermal maturity and similar pore volume and specific surface area to that of Cambrian shale. Permian shale has very complex mineral composition, with large pore diameter, low to medium thermal maturity and small specific surface area. Mineral composition, thermal maturity and tectonic preservation conditions are the main factors controlling shale reservoir development. Siliceous minerals in Cambrian shale and Ordovician–Silurian shale are mainly of biological origin, which make the support capacity better than Devonian–Carboniferous shale and Permian shale (siliceous minerals are mainly of terrigenous origin and biological origin). Thermal maturity of Ordovician–Silurian shale and Devonian–Carboniferous shale is moderate, with a large number of organic pores developed. Thermal maturity of Cambrian shale and Permian shale is respectively too high and too low, the development of organic pores is significantly weaker than the two sets of shale above. There are obvious differences in tectonic preservation conditions inside and outside the Sichuan Basin. Shale reservoirs inside the Sichuan Basin are characterized by overpressure due to stable tectonic activities, while shale reservoirs outside the Sichuan Basin are generally normal–pressure. Four sets of marine shale in South China all have certain resource potentials, but the exploration and development of shale gas is still constrained by complicated geological conditions, single economic shale formation, high exploration and development costs and other aspects. It is necessary for further research on shale gas accumulation theory, exploration and development technology and related policies to promote the development of China’s shale gas industry.

Pore Characteristics and Influencing Factors of Marine and Lacustrine Shale in the Eastern Sichuan Basin, China

Although almost all the shale gas in China is exploited from marine shale (Wufeng–Longmaxi Formation) in Sichuan Basin and several prolific wells, it has also been obtained in Jurassic lacustrine shale. However, the reservoir conditions of the lacustrine shale are not well understood, which has impeded a breakthrough regarding lacustrine shale gas in Sichuan Basin. To probe the reservoir conditions of the lacustrine shale in Sichuan Basin, we take the Wufeng–Longmaxi shale and Dongyuemiao shale sampled from wells and outcrops as examples. A series of experiments were conducted, including TOC, XRD, FE-SEM, N2 adsorption, Micro-CT, vitrinite reflectance and bitumen reflectance. The results show that the pores in marine shale are mainly composed of organic-matter-hosted pores (OM pores). However, in the lacustrine shale, the pores are mainly composed of dissolution pores and intergranular pores. The marine shale is characterized by small-caliber and large-volume pores in which cluster pores are levitated in the shale as kites and connected by past channels. However, in the lacustrine shale, the cluster pores and the past channels are mainly arranged according to the flow channels in the vertical direction. The arrangement of the pores in the marine shale is obviously deformed by compaction. The lacustrine shale is characterized by under-compaction. It can be deduced that the sweet spots for lacustrine shale gas are likely located at the areas characterized by under-compaction resulting from fluid pressure conducted upward, such as the hinge zone of syncline or the core of anticline overlap on the gas reservoirs.

Biomarkers, light hydrocarbons, and diamondoids of petroleum in deep reservoirs of the southeast Tabei Uplift, Tarim Basin: Implication for its origin, alteration, and charging direction

The Atan Bulge in the southwestern Tabei Uplift of the Tarim Basin provides insights into the geochemistry of the oils and condensates in deep Ordovician reservoirs because its reservoir burial depth is generally greater than 6000 m. To investigate the oil origin, alteration, and migration pathways, the carbon isotopes, biomarkers, light hydrocarbons, and diamondoids of 16 oil and condensate samples from the Ordovician reservoirs in the Atan Bulge were analyzed. The results show that chain alkanes dominate the light hydrocarbons, followed by cycloalkanes and aromatic hydrocarbons. 1-methyladamantane (MA) dominates the diamondoids, followed by 1,3-dimethyldiamantane (DMD). The samples lacked biodegradation and thermochemical sulfate reduction signatures. Except for a few samples near the Manjiaer Depression, the evaporative fractionation caused by late natural gas charging is generally weak. The oil geochemistry suggests that the oils and condensates are primarily derived from lower Cambrian marine shale, and the organic matter is mainly type II. The equivalent vitrinite reflectance (Rc) calculated using thermal maturity indicators derived from methylphenanthrene, methyldiamantanes, and C5–C7 light hydrocarbons, respectively, is in the ranges of 0.78%–1.04%, 1.1%–1.5%, and 1.06%–1.48%. The samples' low (3-+4-)-methyldiamantane concentrations (36–76 μg/g) imply a low level of oil cracking. The carbon isotope distribution among oil fractions and different maturity ranges suggest that crude oil was generated and charged multiple times. The maturity of the samples decreases from SSE to NNE, indicating that the petroleum likely migrated from strike-slip faults during its primary charging period, with the Manjiaer Depression and its slope serving as the primary source kitchens.

E&amp;P Notes (November 2022)

E&amp;P Notes (November 2022)

Hydrocarbon Retention and Its Effect on Pore Structure Evolution of Marine Shale Based on Pyrolysis Simulation Experiments

Hydrocarbon Retention and Its Effect on Pore Structure Evolution of Marine Shale Based on Pyrolysis Simulation Experiments

Bulk and intramolecular carbon isotopic compositions of hydrocarbon gases from laboratory pyrolysis of oil shale of the Green River Formation: Implications for isotope structures of kerogens

Evaluation of intramolecular isotope distributions within organic compounds can provide important insights into gas formation processes and structural properties of gas-generating precursors, such as kerogen, bitumen, and oil, in natural reservoirs. Until recently, little has been known about the intramolecular isotope distributions within kerogens. In this study, we conducted systematic pyrolysis experiments of gas generation from a lacustrine oil shale of the Eocene Green River Formation under hydrous and anhydrous conditions (equivalent maturity or Easy %Ro: 0.76 to 3.27 at 310 to 480 °C for 3 to 50 days), measuring gas yields and compositions, as well as bulk and position-specific (PS) carbon isotope compositions. Gas generation processes were investigated in combination with kinetic Monte Carlo (kMC) simulations on a model Type I kerogen based on the chemical structures of oil shale of the Green River Formation. The comparison of our experimental results with kMC modelling indicates a series of β-scission, radical isomerization, and recombination reactions better represent the bulk isotope compositions of propane in the pyrolysis of the oil shale of the Green River Formation, but the ΔCc-t (= δ13Ccen – δ13Cter) values of propane at Easy %Ro > 1.5 can be better simulated by a simple combination of propyl groups with H radicals. Combining our previous works on marine shale of the Woodford Formation and Springfield Coal Member of the Carbondale Formation, PS carbon isotopes of propane indicate that in the lacustrine shales of the Green River Formation and the marine Woodford Shale, propane is sourced from CC bond cleavage, while CO bond cracking generates propane from coal at the initial kerogen cracking stage. At high maturity, the differences of late-stage propane production among the source rocks lead to the different bulk and PS C kinetic isotope effects of propane. Our findings suggest that the δ13C at the terminal position of propane precursors is likely up to 3.6‰ higher than at the central position in the Green River kerogen, while they are similar in the marine shale of Woodford Formation. In addition, the δ13C at the central position of propyl groups attached to heteroatom compounds is relatively more positive in the Springfield Coal Member of the Carbondale Formation than in Green River kerogen. A comparison of intramolecular C isotopes of propyl groups in the kerogens with their bulk δ13C, based on the PS δ13C of early-generated propane, contributes to our understanding of heterogeneities of isotopic structures of sedimentary organic matter.

Development Characteristics and Distribution Patterns of Fractures in the Wufeng-Longmaxi Formation Shale in the Southwestern Sichuan Basin, China

Abstract As the important storage space and main seepage channel of the shale gas reservoirs, fractures control the migration, enrichment, and preservation of shale gas. Therefore, studying the development characteristics of fractures within shale is the key to the exploration and development of shale gas reservoirs. Based on core observation, microscopic thin section examination, field-emission scanning electron microscopy (FE-SEM) analysis, and three-dimensional seismic attribute analysis, this paper studies the development characteristics and distribution patterns of fractures in the Wufeng-Longmaxi Formation shale in the southwestern Sichuan Basin. The results show the following: (1) Both macrofractures and microfractures are developed in the Wufeng-Longmaxi Formation shale in the study area. On the macroscale, horizontal bedding fractures, low-angle slip fractures, vertical shear fractures, and high-angle fractures are mainly developed; on the microscale, intergranular fractures, intragranular fractures, abnormally high-pressure fractures, hydrocarbon generation shrinkage fractures, bedding fractures, etc. are mainly developed. These fractures of different scales work together to create an intricate fracture system within the shale. (2) Based on the 3D seismic attribute analysis, the distribution patterns of fractures was studied in the research area. It was found that nearly east-west-trending and nearly south-north-trending large faults were mainly developed in the Wufeng Formation and the Long-11 submember, with accompanying small faults and secondary fractures. From the bottom boundary of the Wufeng Formation to the top boundary of the Long-11 submember, the fault development shape is unchanged, and the secondary fractures are developed gradually densely, showing the characteristics of a zonal distribution in the entire study area. From the bottom boundary of the Wufeng Formation to the top boundary of the Long-11 submember, the development of microfractures shows variation in different zones. Microfractures are mainly developed around large faults, and the development range of microfractures decreases from bottom to top, but the development of microfractures is gradually intensive. The microfractures are densely distributed from the central to the southern part of the study area (gradually from convergence to divergence), are sparsely distributed in the western part of the study area, and are densely and widely distributed in the northern, northeastern, and northwestern parts of the study area. The research results can provide some guidance for the prediction of shale gas sweet spots in this area, which is beneficial to the further exploration and development of marine shale gas in this area.