S2 Values Research Articles

Evaluation of Ranikot Sandstone Formation, Punjab Platform Basin Pakistan

Abstract The Ranikot sandstone Formation was investigated using TOC and Rock-Eval pyrolysis measurements. Ranikot Formation encountered in Bijnot well, Fort Abbas has been evaluated, which lies in Bahawalpur, middle Indus basin, particularly in Punjab platform. Analysis has been performed on sandstones, twenty well cutting samples of Ranikot Formation has been evaluated. Formation is predominantly sandstone with interbeds of shale. The analysed samples contains TOC ranging from 0.76-3.1 wt.%, The S2 values of Rock-Eval shows poor potential with values ranging from 0.46-1.05 mg HC/g rock. The samples have low hydrogen index values ranging from 21-113 mg HC/g TOC. Kerogen is predominantly Type III land derived organic matter. The analysed samples have Tmax ranging from 413-509 °C. The upper part of formation from 490-560m depth generally exhibits good to very good TOC content and is in the transition between immature and mature zone (Tmax 430-431 °C). The genetic potential in the entire rock unit is poor < 2.0 mg HC/g rock. On the basis of analysis performed the studied samples have shown that the formation has poor potential.

Environmental impacts and cost overrun derived from adjustments of a road construction project setting

Road infrastructure works are complex and important undertakings for the social and economic development of a country. They are based on studies that ensure the technical, environmental and economic feasibility of the work. These studies are the basis of the road executive project, which includes the projects that characterize the work to be performed. Road constructions can be considered as horizontally arranged, integrated and complementary activities, so that each of them establishes boundary conditions that affect all the others. Thus, modification of any part of the project changes the proposed scenario for the execution of the following work stages. Most executive road construction projects must be readjusted during the construction because of deficiencies and incomplete surveys and field studies. Those modifications extend the construction period of the road, alter the contractual value and the environmental impacts of the work. This paper investigates the environmental impacts, associated with the input and output flows, as well as the cost overruns of the construction of a road, considering the activities foreseen in the awarded project (scenario S1) and those executed by the construction company (scenario S2) using a Life Cycle Assessment (LCA). The adjustments done in scenario S2 accounted for an average increase of 16% of the environmental impacts in relation to S1 impacts. The critical stages of those activities were clay mining, embankment construction, base construction, and paving. Although the clay and soil volume moved in the construction process was five-fold higher than the volume of aggregate material, the impacts of the exploration and processing of the rock aggregates were 27% higher. Comparing the costs of both S1 and S2 scenarios, the final contractual values of scenario S2 were average 30% higher than the scenario S1 projected costs. Specifically, the S2 costs of earthwork and paving stages were 45% and 11% higher than S1 respectively. The ground of cost overruns and delays during construction are forecasting errors for soil movement and usage of rock aggregates. The results also shown that LCA application after to completing the executive design of a road can help road designer and contractor during the decision-making processes, to anticipate the potential environmental impacts that road construction can produce, as well as predict the environmental effects of changes on the executive project.

Organic facies and palynology from the middle to late Devonian of the Pimenteiras Formation, Parnaíba Basin, Brazil

A detailed study of organic facies and palynological assemblages was carried out on 11 samples of potential hydrocarbon source rocks of the Pimenteiras Formation, an outcropping at the western edge of the Parnaíba Basin, Brazil. The main objectives are to characterize the depositional paleoenvironment and hydrocarbon source potential. The selection of this outcrop occurred in the function of its preservation and accessibility, and the samples collection observed 1 m of vertical spacing. Generally, the organic matter and the palynomorphs showed a good state of preservation and fluorescence. The most notable spores and acritarchs and phycomates species were discussed in light of international biozones, and the chronostratigraphic range defined as Late Eifelian - Latest Frasnian in age. TOC results show ranges from 0.40 to 2.91%, with most samples showing greater than 1%, thereby holding a high potential generation. The S1 values were virtually null, and the S2 peak ranged from 0.9 to 5.33 mg/g. The kerogen 435 °C, and the ICE between 4.0 and 4.5 demonstrating the material immaturity. For the palynofacies associations definition, only 10 out of the 25 total quantified of subgroups of kerogen categories were considered in the counting of 300 particles. A dendrogram constructed based on these results through cluster analysis, revealed four palynofacies, as follows: I constituted mainly by palynomorphs (acritarchs, prasinophytes and sporomorphs); II – Dominance of Translucent organic matter (cuticles, epidermal tissue and translucent phytoclasts with and without structure); III - Dominance of Opaque/non-fluorescent (opaque phytoclasts and non-fluorescent AOM) and IV - Dominance of AOM fluorescent (amorphous organic matter with fluorescence). The palynomorphs are the most abundant constituents of all studied kerogen. Quantitative analysis based on the distribution of palynomorphs groups throughout the section indicates the dominance of sporomorphs in the palynological assemblages from the Middle Devonian aged samples. On the other hand, occurred the predominance of microplankton elements in the Late Devonian aged samples. Thus, the depositional paleoenvironment was established as a distal oxic mud-dominated shelf with the deltaic influence of the Late Eifelian to Late Givetian, and there is a tendency distal (dysoxic-anoxic ‘shelf’) from the Frasnian, which indicates the maximum flooding surface.

Delineation of factors that control hydrocarbon source rock maturity in Anambra and Abakaliki Basins South-Eastern Nigeria

Outcrop information from Abakaliki and Anambra were used in this study to characterize the source and reservoir rocks in the two basins in order to give indication(s) for hydrocarbon generation potential in the basins to minimize uncertainty and risk that are allied with exploration and field development of oil and gas. Outrop mapping method was used to carry out geological, stratigraphical, geochemical, structural, petrographical, and sedimentological studies of rock units from outcrop sections within the two basins. Thirty-eight samples of shale were collected fromthese Basins in stratified mode of random sampling, and geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed, to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural mapping were used to develop a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥𝟏𝒘𝒕%, Tmax ≥𝟒𝟑𝟏℃, Vitrinite reflectance values are ≥𝟎.𝟔%, and S1+S2 values are >𝟐.𝟓𝒎𝒈/𝒈 for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin show that S 1 +S 2 values range from <𝟏−𝟐𝟎𝒎𝒈/𝒈, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from 𝟒𝟐𝟑℃−𝟒𝟔𝟔℃. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. Keywords: Source rock, kerogen type, Abakaliki Basin, Anambra Basin, Oil generating window

The Petroleum System of Zubair Formation in Zubair Subzone, Southern Iraq

The Lower Cretaceous Zubair Formation is the most important reservoir in the south of Iraq and adjacent countries, as well as the shale intervals, may be the possible source rock. The parameters of the possible source rock within Zubair Formation are accepted, regarding quantity, quality, and thermal maturity.&#x0D; From the total organic carbon values standpoint, shale intervals of Zubair Formation are generally good source rocks, except in the lower parts. While the kerogen types are generally type III gas-oil prone, mix type II/III, and type II oil-prone. The main type of organic matters was amorphous organic matters, which is principally related to oil-prone source rock.&#x0D; The Rock-Eval Pyrolysis shows that the organic geochemical properties presented an effective and/or potential source rock depending on the values of S1, S2, and S3 and their derivatives. The source rock has started the oil expulsion, where the S1/TOC values were mainly more than 0.2 mg HC / g TOC.&#x0D; The modelling explains that the Zubair Formation, wholly, has been entered the onset, partially, the peak, and rarely the end of oil generation in the studied Subzones. This conclusion depends on the calculated temperatures, geothermal gradients, and Vitrinite reflectance calibration.

Geochemical characteristics and effectiveness of thick, black shales in southwestern depression, Tarim Basin

An interval of black shales deposited from Precambrian to lower Cambrian from the southwestern depression of the Tarim basin (SDTB) was systematically evaluated in terms of hydrocarbon potential, organic matter, depositional environment and oil-source relationship. The shales have good TOC contents (up to 3.15%) but low S1+S2 values (<0.03 mg/g), indicating the source rocks are currently at high thermal maturities. The relationship between pristane/n-C17 and phytane/n-C18 indicates the kerogen was oil prone and dominant by algal input. Furthermore, the depositional environment had relatively moderate salinity and stratified water environment indicated by G/C30H ratios (0.15–0.24). The high algal input may have enhanced TOC preservation under reducing conditions reflected by high dibenzothiophene content and low pristane/phytane ratios (mean 0.79). Thus, these source rocks may have generated a significant amount of oil during their geological history. Additionally, in view of the molecular geochemistry indicators, the extracts of black shales hold marked differences with the Cambrian-Ordovician end-member oils, but are quite similar to oils in the northeastern portion of the SDTB. It means that the lightly explored SDTB may contain significant hydrocarbon resources, and coeval source rocks in the ultra-deep portion of the basin may have contributed to the prolific petroleum resources in the Tarim Basin.

A new method for predicting sweet spots of shale oil using conventional well logs

Abstract In this paper, a new method called sweet spot index (SSI) is proposed by the combination of shale oil mobility and shale reservoir fracability to predict the vertical distribution of shale oil sweet spots using conventional logs. In the SSI method, logging evaluation models for TOC, S1 (volatile petroleum), and mineral content are initially established. Mobile oil content is obtained by subtracting the amount of adsorbed oil from the total oil content, which is the S1 value after the recovery of light and heavy hydrocarbons. The adsorbed oil content is calculated based on the oil adsorption model established by a stepwise pyrolysis experiment. The formation fracability is estimated by a combination of estimates of brittle mineral content and Young's modulus. Formations with higher brittleness and lower Young's modulus are considered better simulation candidates. The SSI value is the product of the normalized mobility and the fracability index, which minimizes the section of just an organic matter sweet spot (i.e., high oil content) or an inorganic sweet spot (i.e., easily fractured) and has the advantage of accurately predicting its vertical distribution. In the case study, the new method is successfully implemented to predict sweet spots of the Es3L (lower sub member of the third member of the Eocene Shahejie Formation) in the Bonan Sag, Bohai Bay Basin, China. The lower limit value of SSI is set to 0.1 based on its relationship with shale oil production. The effectiveness, reliability and adaptability of the SSI method have been verified by three wells in the Bonan Sag.

Geochemical characteristics, hydrocarbon potential and depositional environment of the Yangye Formation source rocks in Kashi sag, southwestern Tarim Basin, NW China

Abstract The Yangye Formation sequence is widely exposed in Kashi sag, Tarim Basin, NW China. To investigate geochemical characteristics and depositional environment of the Yangye Formation successions, 26 samples from an outcrop kzgs section in the north and 21 core samples from YD-1 well in the south were subjected to various geochemical analyses. The average TOC content is 1.87 wt % in the kzgs section and 1.36 wt % in the YD-1 well, and most samples have fairly high TOC contents (>1.0 wt %). Notably, samples in the YD-1 well are characterized by high S1, S2, HI and PG values, compared to those in the kzgs section. Based on pyrolysis data, organic matter (OM) in the kzgs section consists predominantly of type III kerogen with gas prone, whereas OM in the YD-1 well have oil/gas prone characters with dominating mixed type II/III and type III kerogen with minor type II kerogen. Tmax values (447–469 °C and 453–484 °C, respectively) imply that source rocks in the kzgs section are within peak to late mature stages, and samples in the YD-1 well contain late mature to post-mature OM, consistent with the results of Ro, PI, CPI, and biomarker maturity parameters. The distributions of n-alkane, isoprenoids, sterane and terpane, as well as carbon isotopes, suggest a predominance of algal, bacterial and planktonic OM, but with terrigenous higher plants influenced. However, samples in the kzgs section probably received more contributions of terrigenous and bacteria-reworked materials. Moreover, OM in the kzgs section was likely preserved in a suboxic, fresh/brackish condition, while OM from the YD-1 well was developed under a suboxic to oxygen-depleted, fresh with brackish influenced environment. There have distinct differences in organic richness, OM types and thermal maturity between the kzgs section and YD-1 well. Overall, the Yangye Formation in the whole Kashi sag still has fair to good hydrocarbon potential, and source rocks in the YD-1 well have more favorable potential to generate considerable oil and gas hydrocarbons.

Rapid Quantification Analysis of Alcohol During the Green Jujube Wine Fermentation by Electronic Nose

In order to explore the applicability of electronic nose technique for alcohol dynamic change, electronic nose was used to predict the alcohol content of the green jujube wine fermentation. The principal component regression (PCR) and multiple linear regression (MLR) were applied to establish the forecast model of the alcohol content. The results showed that the response values of sensors S1, S8, S3, S5 and S4 were the largest among the 10 sensors and changed significantly during 7 days of fermentation. The linear simulation equation was established by using the MLR to predict the alcohol content and the R2 value was 0.949, and the RMSEC was 0.974. The model shows the better predict alcohol content correlation (R2=0.946) and RMSEP (1.016). The results show that it is feasible to use the electronic nose system to analyses alcohol content dynamic chance of the green jujube wine fermentation, and electronic nose technique provides a method for rapid quantification analysis of alcohol of wine fermentation.

Hydrocarbon generation potential of residual kerogens in high-over matured shale rocks and its contribution to shale gas reserves

A low matured shale rock from Lucaogou Formation in the Santanghu Basin was thermally simulated using semi-open system pyrolysis experiment in attempt to evaluate its late gas generation potential. The Rock-Eval results showed that the residual kerogen in the high-over matured shale rocks still possess some hydrocarbon generation potential. The amount of the pyrolyzable hydrocarbons (S2) generated from the residual kerogen ranged from 0.57 to 1.02 mg HC/g rock. The S2 and hydrogen index (HI) values began to diminish at EasyRo > 1.45%. About 1 m3/t rock of methane was estimated from Lucaogou Formation at high-over maturity stage. This indicates that the hydrocarbon generation potential of residual kerogens in the high-over matured shale rocks have a significant contribution to shale gas reserves.

Organic Matter Type, Maturity, Depositional Environmental Characteristics, and Liquid Hydrocarbon Potential of Late Carboniferous Kozlu Bituminous Coal and Coaly Shale Beds (Zonguldak-Amasra Basin, NW Anatolia, Turkey): An Application of Biomarker Geochemistry

The Upper Carboniferous (Westphalian A) Kozlu Formation consisting chiefly of sandstone, thick coal layers, shale, and conglomerate levels crops out in the Zonguldak-Amasra Basin, NW Anatolia. The Kozlu Formation contains a total of 20 mineable coal layers with the thickness varying from 0.5 to 6 m. The lower level of formation is represented by lacustrine deposits, whereas the upper part is made up of thick flood plain sediments and meandering river deposits bearing laterally continuous coal levels. In this study, coal samples taken from coal layers within the Kozlu Formation at the Kozlu Underground Coal Mining site were evaluated using the data obtained from pyrolysis/total organic matter (TOC), gas chromatography, and gas chromatography–mass spectrometry. The average total organic matter (TOC) value of Kozlu coals is 40.28%. The coals are characterized by relatively high hydrogen index (HI) value (average 262 mg HC/gTOC) and very low oxygen index value (2 mg CO2/gTOC). Pyrolysis data indicate that coals contain dominantly type II and less amount of type III kerogen, and Tmax values range from 454 to 468 °C. In gas chromatographs, the recorded distribution consists predominantly of low-carbon-numbered n-alkanes and subordinately of high-carbon-numbered n-alkanes and the terrigenous/aquatic ratio value is very low (0.05–0.09). Pristane abundance is greater than that of phytane, and Pr/Ph ratios are in the range of 1.11–1.60. The sterane abundances in the Kozlu coals are in the following order: C29 > C28 > C27. Coals have high C19 and C20 tricyclic terpane concentrations and high (C19 + C20)/C30 ratio, high C30* (diahopane) and C29Ts concentrations, and high C30*/C29Ts ratio and low C31R/C30 and C29/C30 hopane ratios. The dibenzothiophene-to-phenanthrene ratio of Kozlu coals is found to be very low (0.04–0.14). Based on the pyrolysis and biomarker data, the Kozlu coals are interpreted as being deposited in a suboxic–oxic continental environment in which there is effective input of clay and dominantly terrestrial (with significant lipid-rich components) and bacterial organic matter. High Tmax values, CPI values close to 1, low moretane/hopane (0.23–0.12), equilibrated 22S/(22S + 22R) homopane (for C32), 20S/(20S + 20R) C29 sterane (0.52–0.54) and TA(I)/TA(I + II) steroid ratios, high ββ/(ββ + αα) sterane (0.51–0.55), C30*/C29Ts, C30*/(C30* + C30H), MPI-3(α/β) (1.24–1.41), and MDR and MA(I)/MA(I + II) steroid are indicative of mature–late mature organic matter. Ro values between 0.9 and 1.25% determined from Tmax (454–468 °C) values indicate “high-volatile bituminous B–medium-volatile bituminous” rank for Kozlu coals. Kozlu coals having HI values (up to 331 mg HC/gTOC) extremely higher than those of classical coals indicates that these coals have significant oil and gas generation potential, and high S1 (average 6.04 mg HC/g rock) and S2 (110.08 mg HC/g rock) values imply that they generate notably high amount of liquid hydrocarbons and still have generation potential.

ANALISIS KESESUAIAN LAHAN TAMBAK BERDASARKAN PARAMETER FISIS &amp; CHEMIS UNTUK BUDIDAYA KEPITING BAKAU (Scylla spp) DI KELURAHAN DEGAYU KOTA PEKALONGAN

This study is to determine the level of land suitability as well as assessing the extent to which the &#x0D; potential of land resources can be utilized for the cultivation of mangrove crabs. The purpose of this &#x0D; research is to know the level of land suitability based on physical and chemical parameters for the &#x0D; cultivation of mangrove crab in the pond area in Degayu Village. This research was conducted on 4 &#x0D; until 9 June 2018 at 4 ponds in Degayu Village. Water parameters measured are temperature, salinity, &#x0D; water pH, DO, ammonia, nitrate, phosphate, soil texture, soil pH. The feasibility analysis of pond land &#x0D; is done by using Scoring Method with 3 values of feasibility class interval that is very suitable (S1), &#x0D; according (S2), not appropriate (S3). The result from 4 point of pond station representing Degayu &#x0D; Subdistrict showed temperature value ranged from 31-34 ºC, salinity ranged between 18-28 ppt, water &#x0D; pH ranged from 6,3-7,9 ppm, DO ranged from 3.0-6,0 ppm, ammonia ranged from 0.1-0.3 mg/l, &#x0D; nitrate ranged from 1.4 to 1.8 mg / l, phosphate ranged from 1 -2 mg / l, soil texture was generally &#x0D; dominated by a mixture of clay / clay, sand, and dust and soil pH ranges from 7.0 -7.5. At station 1,3 &#x0D; gets S1 value (very suitable) while station 2,4a, and 4b got S2 value (accordingly). Pond in Degayu &#x0D; village has a category of appropriate feasibility class (S1) to support the activities of mangrove crab &#x0D; cultivation.&#x0D; Keywords: Crab, Land suitability, Water quality and soil parameters

Organic geochemistry of the Lower Permian Tak Fa Formation in Phetchabun Province, Thailand: implications for its paleoenvironment and hydrocarbon generation potential

The outcrop samples of the Tak Fa Formation (Lower Permian) in Phetchabun Province have been studied to determine their organic geochemical characteristic, depositional paleoenvironment, and hydrocarbon generation potential. The total organic carbon (TOC) values ranging from 1.42 to 4.58 wt% and extractable organic matter values ranging from 76.84 to 197.65 ppm of the Tak Fa Formation were generally low and associated with low S2 values (0.00–0.50 mg HC/g rock) and hydrogen index values in range of 0–32 mg/g TOC, although this could reflect highly thermal maturity and complex tectonic history. Thus, kerogen classification can be based on a non-biomarker study for these outcrop samples instead. The non-biomarker plot, Pr/n-C17 and Ph/n-C18 from this study indicates that organic matter originally comes from type II/III kerogen. The samples were also investigated and indicated that the organic matter inputs were derived from mixed marine and terrigenous sources and deposited under suboxic to oxic conditions. The depositional environment of the Tak Fa Formation in this study is interpreted to be an estuarine environment or restricted lagoonal carbonate platforms. This has been achieved from normal alkane and isoprenoids distributions, terpane, and sterane biomarkers. Thus, the Tak Fa Formation is considered to be a hydrocarbon source rock during the time of the deposition. Although the geochemical data in this study indicate that the Tak Fa Formation has experienced high maturation, one or more locations could meet a condition that places this formation to be an active source rock. The approach and concepts presented in this study can be applied to similar evaporite-carbonate deposits in Thailand to find more petroleum plays.

Influence of different irrigants on substance P and IL-8 expression for single visit root canal treatment in acute irreversible pulpitis.

The aim of this study was to assess the influence of ketorolac tromethamine and dexamethasone on substance P and IL-8 expression when used as a root canal irrigant for single visit root canal treatment for acute irreversible pulpitis. A total of 42 patients with pain due to acute irreversible pulpitis in carious premolar and molar teeth were included in this study. The four irrigation groups were as follows: saline (n=11), 3% sodium hypochlorite (n=11), ketorolac tromethamine (n=10) and dexamethasone (n=10). Blood samples S1 and S2 were collected upon access opening and after canal preparation, respectively. Quantification of substance P and IL-8 were done using ELISA test. Post-operative pain was assessed by questioning the patients. The difference between S1 and S2 sample values for the four different irrigant groups was not significant. The sodium hypochlorite group had a higher mean expression of substance P and IL-8 values. Dexamethasone irrigation was more effective in controlling post-operative pain.

Insights from Rock-Eval analysis on the influence of sample weight on hydrocarbon generation from Lower Permian organic matter rich rocks, West Bokaro basin, India

Abstract Among the different Rock-Eval parameters, the hydrocarbons released under the S2 peak of Rock-Eval is of significance as it indicates the residual hydrocarbon content of the rock. Further, through its relationship with total organic carbon (TOC) content, it helps in calculating hydrogen indices (HI) which helps in understanding the type of organic matter present in a rock [HI= (S2/TOC)*100]. The present study documents the role of sample weight/amount used for analysis on the Rock-Eval S2 parameter for unconventional source-rock characterization. For the purpose of this study, a vitrain band sample type (manually isolated from a coal), a high-TOC shale sample type, and a carbonaceous shale sample type were analyzed at two different particle sizes (viz. 1 mm-500 μm and 212-75 μm) and different sample weights (5–15 mg for organic matter rich rocks and 30–60 mg for shale) using a Rock-Eval basic cycle (heating rate at 25 °C/min). Although S2 is reported as mg hydrocarbon (HC)/g rock, with increase in sample weight, an increase in hydrocarbons released under the S2 peak of Rock-Eval was observed for all three sample types for both the particle sizes. The observations were further validated using a Norwegian geochemical standard (JR-1). Further, all samples were reanalyzed by conducting pyrolysis experiments at a lower heating rate of 5 °C/min. The impact of sample weight on S2 and HI was observed to be more pronounced for the JR-1 standard (higher hydrocarbon yield) than the Van Krevelen Types III-IV organic matter-bearing rocks. It thus calls for interpreters to be aware of the influence of mass of organic matter on hydrocarbon generation, and to monitor the maximum S2 values of organic matter-bearing rocks, within the flame ionization detector (FID) detection limits. Further, it is recommended that for Type III organic matter-bearing rocks with TOC content>20 wt %, elemental analysis should be used to derive atomic H/C and O/C ratios for Van Krevelen diagram-based kerogen typing.

The geochemical characteristics and gas potential of the Longtan formation in the eastern Sichuan Basin, China

The Longtan Formation in the Sichuan Basin contains abundant organic-rich mudstones and coals, however, few studies have been conducted about their gas potential. A comprehensive study has been conducted on the Longtan sediments in order to determine their critical properties and gas potential. The Longtan samples, especially the coals, contain abundant organic matter, whereas S1 and S2 values are generally very low due to high thermal maturity. The organic component is dominated by the vitrinites, which comprises more than 95% of dispersed organic matter. The high vitrinite reflectance values (∼1.88–2.14% Ro) indicate a post thermal maturity of these sediments, which is consistent with the reliable Tmax values. The predominant mineral components are clay minerals and quartzs, and the brittle nature of the studied samples can be confirmed by the high contents of the brittle minerals and high brittleness indexes. The porosity positively correlates with total organic carbon (TOC), and abundant organic-matter, intraparticle, interparticle pores and fractures have been detected in these studied samples. The Longtan Formation in the study area was mainly deposited in an oxic environment. According to the 1D basin modelling, the Longtan sediments reached the maximum Ro after they have been buried to the maximum depth at late Cretaceous, and they began to generate gas at middle Jurassic. Attention shall be paid on the co-exploration and co-exploitation of shale gas and coalbed methane of the Longtan Formation of eastern Sichuan Basin in the future.

Mineralogy and organic geochemistry of the terrestrial lacustrine pre-salt sediments in the Qaidam Basin: Implications for good source rock development

Abstract Terrestrial pre-salt sediments are not only good lithologic reservoirs similar to marine pre-salt carbonates, but also are supposed to have high hydrocarbon generation potential because the overlying terrestrial thick-bedded salts are generally preserved in basin centers. However, their status as source rock has attracted much less attention than as reservoir. In this paper, we choose the Qaidam Basin as an example and study the minerology, organic geochemistry, and organic petrology of the pre-salt sediments in a hydrocarbon-rich unit, where abundant petroleum resources have been discovered under halite beds. LithoScanner logging of six wells and X-ray diffraction results of 378 samples show that terrestrial pre-salt sediments are characterized by mixed siliciclastic-carbonate-sulphate rocks and their relative proportions are laterally varied. Quartz, feldspar and clay minerals are of allochthonous origin and classified as argillaceous endmember while dolomite and ankerite are of autochthonous origin as carbonate endmember. Organic geochemistry analysis of 118 samples show great variability in TOC, S2, and Tmax values, and this variability is not related to mineral composition heterogeneity as hydrogen index is not well correlated with detritus, carbonate, and sulphate minerals contents, indicating the interacting controls of source rocks by both exogenetic and endogenetic processes in brackish-mesosaline lakes. Strong bacterial reworking of organic matter results in the dominant macerals of pre-salt sediments as bituminite and oil generation at low maturity levels. Sealed by impermeable halite beds and in close proximity to reservoirs, the generating hydrocarbon by pre-salt good source rocks is effectively accumulated, which entails hydrocarbon exploration under halite beds in other terrestrial salt-bearing basins.

Depositional and organofacies influences on the petroleum potential of an unusual marine source rock: Waipawa Formation (Paleocene) in southern East Coast Basin, New Zealand

Abstract The Paleocene Waipawa Formation is a widespread, ∼2–80 m-thick marine mudstone that occurs in several New Zealand basins. It is relatively enriched in organic matter (OM) and is the inferred source of a sub-commercial oil discovery and several correlated oil seeps. To determine the organofacies and depositional influences on the petroleum potential of the formation, we have undertaken a high-resolution, multidisciplinary study of the Taylor White section in the central East Coast Basin. This section is the thickest stratigraphically coherent surface exposure of the formation and includes contacts with the bounding Whangai and Wanstead formations. Bathymetric indicators within the foraminiferal assemblages indicate a slope setting for the section, deepening from middle to lower bathyal through the Waipawa–Wanstead succession. Significantly, the Whangai Formation in this section is barren of foraminifera. Dinoflagellate and calcareous nannofossil biostratigraphy provides somewhat conflicting age control but a resulting age model indicates a tenfold increase in compacted sediment accumulation rate during Waipawa deposition (from ∼1 to ∼10 cm/ky). Our multivariate statistical analysis of geochemical and paleontological data reveals systematic variation in paleoenvironmental and source rock parameters within the section, with samples forming four distinct clusters or organofacies: OM-rich and OM-poor Waipawa organofacies, Whangai, and Wanstead organofacies. The two Waipawa organofacies are distinguished by enrichments in total organic carbon (TOC) and organic 13C, dominance of phytoclasts (mainly degraded woody plant matter; 66–98%), and low amounts of amorphous organic matter ( Whangai and Wanstead organofacies are characterised by a greater proportion of marine OM but are distinguished from each other by differences in OM preservation: OM is well-preserved with indications of hypoxia in the Whangai organofacies but is poorly preserved in the Wanstead organofacies. Geochemical fingerprinting identifies an interval of Whangai organofacies that separates two phases of Waipawa organofacies deposition. The lower phase comprises four alternations between OM-rich and OM-poor Waipawa organofacies and the upper phase comprises a single pulse of OM-rich Waipawa facies bounded by OM-poor intervals. Overall, Waipawa Formation in this section has TOC and pyrolysable hydrocarbon (S2) values of 0.2–4.6 (mean 2.2) wt% and 0.1–12.4 (mean 3.9) mg HC/g rock, respectively. One-third of S2 values exceed 5 mg HC/g rock, indicating good‒very good bulk petroleum potential, with the remainder having poor‒fair potential. Petroleum potential (S2) increases with increasing TOC (R2 = 0.85). Hydrogen index (HI) values range from 21 to 295 mg HC/g TOC, averaging just 147 mg HC/g TOC. In line with these modest HI values, quantitative pyrolysis-gas chromatography confirms that the petroleum potential is primarily for gas or gas-condensate, with relatively little oil potential. Of the total paraffinic petroleum yield, gas (n-C1–5) contributes 80–100%, whilst total (n-C6+) and non-volatile (n-C15+) paraffinic oil contribute ≤20% and ≤6%, respectively. Despite the low paraffinic oil potentials, n-C6+ and n-C15+ correlate relatively strongly with HI, and less strongly with TOC. The overall gas-condensate-prone nature of the Waipawa organofacies at Taylor White reflects the predominance of woody phytoclasts, which are unlikely to produce paraffinic oil. The small paraffinic oil component is instead more likely to be associated with the marine algal component. Although this component is volumetrically subordinate, the higher paraffinic oil potential appears to result from the combination of high productivity of specific marine algae (i.e., pelagophytes), hypoxic depositional conditions and, most importantly, increased preservation of OM, including through sulfurisation. This raises the possibility of more algal-rich, oil-prone facies existing within the Waipawa Formation in areas with higher TOC or, alternatively, in areas beyond the direct reach of the terrestrial influxes, yet still sufficiently influenced by low water-column oxygen levels and high sulfur contents that promote enhanced OM preservation.

The influence of partial hydrocarbon saturation on porosity and permeability in a palaeogene lacustrine shale-hosted oil system of the Bohai Bay Basin, Eastern China

Palaeogene calcareous (>40% carbonate) mudstones (Ro from 0.56 to 0.88%) from the Bohai Bay Basin were studied by combined petrographical, geochemical and petrophysical analysis in order to assess and quantify the pore space, pore filling and its influence on gas transport capacity.TOC contents ranged from 1.44% to 5.12% and porosities (ΦHe) determined by helium pycnometry, from 1.3% to 6.4%. Bitumen-filled porosity (ΦS1) was estimated to range between 0.3 and 2.0% based on Rock-Eval S1 values and an assumed bitumen density of 0.90 g/cm3. The “true” total porosity (Φtotal = ΦHe + ΦS1) amounts to 1.9–8.5%. The in-situ oil saturation (So) was estimated to range between 25% and 52%, with two samples (L69-1B and L69-2) having relatively high oil saturation (71% and 91%).The conductivity of the remaining “open” pore space was measured on three samples with different orientations and oil saturations from 17 to 24%. The effective Klinkenberg-corrected gas permeability coefficients range between 63 and 2000 nDarcy, and permeability is highest parallel to bedding. Upon loading from 10 to 40 MPa confining pressure the intrinsic permeability coefficients decreased by one order of magnitude, revealing a relatively high exponential stress sensitivity coefficient (0.069 MPa−1) and much lower zero stress permeability (1.416 × 10−6 mD) than most gas shales. This could be due to pore plugging by ductile bitumen.

Where Sobolev interacts with Gagliardo–Nirenberg

We investigate the validity of the fractional Gagliardo-Nirenberg-Sobolev inequality(1)‖f‖Wr,q(Ω)≲‖f‖Ws1,p1(Ω)θ‖f‖Ws2,p2(Ω)1−θ,∀f∈Ws1,p1(Ω)∩Ws2,p2(Ω).Here, s1,s2,r are non-negative numbers (not necessarily integers), 1≤p1,p2,q≤∞, and we assume, for some θ∈(0,1), the standard relations(2)r<s:=θs1+(1−θ)s2 and 1q=(θp1+1−θp2)−s−rN.Formally, estimate (1) is obtained by combining the “pure” fractional Gagliardo-Nirenberg style interpolation inequality(3)‖f‖Ws,p(Ω)≲‖f‖Ws1,p1(Ω)θ‖f‖Ws2,p2(Ω)1−θ(with 1/p:=θ/p1+(1−θ)/p2) with the fractional Sobolev style embedding(4)Ws,p(Ω)↪Wr,q(Ω),0≤r<s,1≤p<q≤∞,1q=1p−s−rN,p(s−r)≤N.Estimates (3) and (4) are true “most of the time”, but not always; the exact range of validity of (3) and (4) has been known. Combining these results, we infer that (1) is valid “most of the time”. However, the validity of (1) when (3) and/or (4) fail was unclear. The goal of this paper is to characterize the values of s1,s2,r,p1,p2,q,θ,N such that (1) holds.