Average Total Organic Carbon Value Research Articles

Shale gas potential evaluation based on well-logs and basin modeling of the Cretaceous-Paleocene succession of the Kohat Plateau, Pakistan: implication for shale gas exploration

This study examines subsurface data from three wells to assess the shale gas potential of the Cretaceous-Paleocene succession of the Kohat Plateau, Pakistan. The petrophysical analysis was performed to calculate total organic carbon (TOC) using the Passey model. Petro-elastic parameters (Poisson ratio, Young modulus, and brittleness) and thermal maturity were also evaluated, respectively. The average TOC values in Makori-01 (as calculated by Passey's method) are 2.88 (wt%) for the Lockhart Limestone and 2.10 (wt%) for the Chichali-1 Formation. In Manzalai-02 well, the Lockhart, Hangu, Kawagarh, Lumshiwal, and Chichali formations TOC values are 2.81 (wt%), 2.55 (wt%), 2.32(wt%), 2.29 (wt%) and 2.20 (wt%) respectively. To exploit the unconventional resources, zones I and II in the Sumari Deep X-01 well (Chichali Formation) with an average TOC value of 2.71 (wt%) can be considered favorable areas for further evaluation. The volume of shale value is resulted as maximum within Chichali Formation in Makori-01 (58.52–75.89%), Manzalai-02 (54.09%), and Sumari Deep X-01 (70.47%), while the least value is noted within Lockhart Limestone in Makori-01 (12.25%) and Manzalai-02 (14.02%), and in Hangu Formation in Sumari Deep X-01 (12.39%). Also, the elastic properties reveal two to four zones of Young modulus, brittleness index, and Poisson’s ratio within the Chichali Formation in the studied three wells. The isopach maps show that the Patala, Lockhart, Hangu, Lumshiwal, and Chichali formations in the research area exhibit variable thicknesses. The 1D maturity models of the Makori-01 and Manzalai-02 wells indicate burial to a depth of 8 km approximately 2.5 Ma ago and the apex of oil production (1.1% Ro). The 1D maturity models indicate that the Sumari Deep X-01 well has encountered minimal burial (in terms of both time and depth) and, as a result, exhibits minimal potential source rock intervals. The volumetric estimate of unconventional recoverable gas resources is approximately 1.57 TCF in the study area. The integrated research provides the basis for tracking and assessing the unconventional resource potential, distribution, and characteristics within the studied basin.

Source rock characterization based on geochemical observations using Well BO-1, Central Sumatra Basin

The Central Sumatra Basin, characterized as a tertiary back-arc basin, stands as one of Indonesia’s foremost hydrocarbon-producing basins. Consequently, in the pursuit of hydrocarbon exploration endeavors, a comprehensive analysis of the potential source rocks within this region becomes imperative. The focal point of this study is the BO-1 well, situated within the Pematang Formation. Geochemical analysis methods, specifically leveraging Total Organic Carbon (TOC) and Rock-Eval Pyrolysis data, were employed to assess the quality, quantity, and maturity of the source rock. The research findings reveal a noteworthy organic material content at a fair-to-good level, registering an average TOC value of 0.69% and a Potential Yield of 1,994 mg/g, both falling within the fair-to-good classification. The Hydrogen Index value designates the source rock as type III kerogen, indicating a propensity for gaseous product generation. Maturity evaluation places the source rock within an immature to mature range, with a maximum temperature range of 383-452°C. In summary, the analysis discerns the source rock within the research area as an effective type, characterized by a substantial organic material abundance at a fair-to-good level and a mature maturity level. This conclusion is reinforced by the lithology of the research area, predominantly comprising mudstone, recognized for its richness in organic material.

Palaeoclimatic influence on lake palaeoenvironment and organic matter accumulation in the Middle Jurassic Shimengou formation (Qaidam basin, NW China)

The formation and accumulation of lacustrine organic-rich shales are strongly related to palaeoclimate and palaeoenvironmental conditions. Middle Jurassic organic-rich lacustrine shales in the Qaidam Basin, NW China, are important source rocks for unconventional oil and gas exploration, but factors controlling their organic matter (OM) abundance and preservation are unclear. To understand how palaeoclimate and palaeoenvironmental conditions influenced depositional processes and elucidate the factors controlling OM accumulation of lacustrine organic-rich shales, we investigated total organic carbon (TOC), mineral compositions, and element geochemistry the Shale Member of the Middle Jurassic (J2s2) Shimengou Formation from the Yuqia Coalfield in the Qaidam Basin. From the bottom to the top, the Shale Member includes three significant stages based on their average TOC values of 5.45% (Stage I), 9.90% (Stage II), and 1.10% (Stage III). Paleoclimate proxies including C-values and Rb/Sr ratios indicate that in Stage I the lake developed under warm and humid conditions, while in Stage II climate changed to hot and arid/semiarid conditions before returning to warm and humid climates in Stage III. Correlation analysis among proxies for palaeoclimate, terrestrial influx (Al2O3 and TiO2 contents), sedimentation rate ((La/Yb) N ratios), palaeosalinity (Sr/Ba ratios and B/Ga ratios), palaeoproductivity (P/Ti ratios and Sibio contents), redox conditions (Corg/P ratios), and TOC values revealed that palaeoclimate had little direct impact on OM accumulation, with palaeoenvironmental conditions the main controlling factor for OM accumulation. OM accumulation in Stage I was primarily controlled by redox conditions, followed by palaeoproductivity, terrigenous influx, and sedimentation rate. In Stage II, high palaeoproductivity and anoxic bottom water conditions controlled OM accumulation, resulting in the deposition of oil shales with abundant hydrocarbon potential. In Stage III, poor OM preservation related to oxic redox condition was the primary controlling factor for OM accumulation. We suggest that variations in lake palaeoenvironments induced by palaeoclimate change controlled OM accumulation and petroleum potential.

Geochemical Characteristics of the Middle Jurassic Coal-Bearing Mudstones in the Dameigou Area (Qaidam Basin, NW China): Implications for Paleoclimate, Paleoenvironment, and Organic Matter Accumulation.

The Qaidam Basin is a prominent oil and gas exploration and production base of NW China's Jurassic coal-bearing strata. Coal-bearing mudstones are important source rocks for unconventional reservoirs and can record valuable paleoenvironment and paleoclimate information. Here, geochemical analysis including total organic carbon (TOC), total sulfur, organic carbon isotopic composition, rock pyrolysis, X-ray diffraction, and major and trace elements were carried out on mudstone samples from the Middle Jurassic coal-bearing strata of the Dameigou section in the Qaidam Basin to reveal the paleoclimatic and paleoenvironmental conditions during the deposition of the strata and their controls on organic matter accumulation. Results show that the Middle Jurassic Dameigou and Shimengou formations include three significant stages based on their average TOC values of (3.32%, Stage I; 0.87%, Stage II; and 4.42%, Stage III) from the bottom to the top. The organic matter in mudstones in Stages I and II are mainly derived from terrestrial higher plants, while the organic matter has mixed sources of higher plant debris and lower aquatic organisms in Stage III. Paleoclimate parameters indicate that the mudstones in Stage I were deposited under humid and warm conditions, while the climate in Stage II changed to semiarid and warm conditions before turning dry and hot in Stage III. The varying paleoenvironmental characteristics under different paleoclimatic conditions have also been reconstructed. Our results suggest that the accumulation of organic matter in Stages I and II was primarily controlled by redox conditions, while paleoproductivity is the major controlling factor for organic matter accumulation in Stage III.

Nano-Scale Pore Structure Characterization and Its Controlling Factors in Wufeng and Longmaxi Shale in the Zigong Area, Southwest Sichuan Basin

The nano-scale pore systems in shale reservoirs control shale gas transportation and aggregation, which is of great significance for the resource evaluation of shale oil and gas and the selection of a “sweet spot”. Taking twelve marine shale samples from the Wufeng–Longmaxi Formation in the Zigong area, southwest Sichuan Basin, as the research target, we carried out a series of experiments, including total organic carbon (TOC) analysis, X-ray diffraction (XRD), gas adsorption (CO2 + N2), and mercury intrusion porosimetry (MIP), to study the full-scale pore structure characterization and controlling factors of pore volume and specific surface area. The results presented the following findings. (1) Marine shale samples from the target area are rich in organic matter, with an average TOC value of 3.86%; additionally, the mineral composition was dominated by quartz and clay minerals, with average contents of 44.1% and 31.4%, respectively. (2) The full-scale pore size distribution curves of pore volume developed multimodally, with the main peaks at 0.5 nm–2 nm, 3 nm–6 nm, and 700 nm–2.2 um; moreover, the full-scale pore size distribution curves of a specific surface area developed unimodally, with the main peak ranging from 0.5 nm to 1.2 nm. (3) Pore volume was mainly contributed by mesopores and macropores, with an average contribution of 46.66% and 42.42%, respectively, while the contribution of micropores was only 10.91%. The specific surface area was mainly contributed by micropores and mesopores, with an average contribution of 64.63% and 29.22%, respectively, whereas the contribution of micropores was only 6.15%. (4) The TOC content mainly controlled the pore volume and specific surface area of micropores and mesopores, while the clay and feldspar content generally controlled the pore volume and specific surface area of macropores. Additionally, the quartz content had an inhibitory effect on the development of all pore types. These results will help researchers understand the laws of gas accumulation and migration.

Seasonal Monitoring of Water Quality Parameters and Pesticides at the Altınapa Reservoir Watershed

Altınapa Reservoir is a reservoir located on the Meram Stream in the Konya Province in Türkiye that supplies drinking water. The Altınapa Reservoir feeds the Konya Drinking Water Treatment Plant with 37.8 million m3 of water annually and the treated water is delivered by the drinking water network. The aim of this study was to determine the effect of agricultural activities and settlements on water quality in the Altınapa Reservoir Watershed. In the study, major water quality parameters (pH, electrical conductivity, total organic carbon, total nitrogen, nitrite, nitrate, phosphorus, phosphate, and total suspended solids) and pesticides were monitored at four stations (K1, K2, K3, K4) on the sub-streams feeding reservoir. Major water quality parameters were monitored at monthly intervals for 12 months between June 2020 and May 2021, and pesticides were monitored seasonally at 4 seasons (Fall 2019, Winter 2020, Summer 2020, and Spring 2021). A correlation matrix was used to assess the connections between nine indicators of water quality. The annual average conductivity and pH values of the samples taken from four different stations of the Meram Stream were 432 µS/cm and 8.04, respectively. The highest value for total nitrogen was 10.73 mg/L and it was 0.87 mg/L for nitrate. Annual average total organic carbon values were determined as 1.35, 1.69, 1.51, and 1.46 mg/L at K1, K2, K3, and K4 stations, respectively. Specific UV absorbance indicated that organic matters of water are mostly hydrophilic and have low aromatic content. In seasonal pesticide monitoring, 71 different compounds were detected in water samples. The compounds whose concentrations exceeded Turkish Environmental Quality Standards were identified as DDD-op, DDE-p.p', diflufenican, and imidacloprid. Pesticides constitute most of the micropollutants detected in water samples. The highest positive correlation among water quality parameters was obtained between conductivity and nitrate (0.81) and total nitrogen (0.88).

Reservoir characterization of the shallow to deep Longmaxi formation in the Weiyuan Block, southwestern Sichuan Basin

Marine shale gas exploration targets are reaching into shallow to deep or ultradeep burial depths. Rock microstructure and reservoir quality emerge as the main risk considerations for a profitable reservoir at these large depths. Shallow to deep marine shales occur in the Silurian Longmaxi Formation of the Weiyuan Block, which is located on the southwestern margin of the Sichuan Basin. However, few details of the characteristics of the Longmaxi shales in this Block have been reported. In this study, five wells approximately 3500 m deep were drilled. Field emission scanning electron microscopy, low-pressure gas adsorption and core plug porosity-permeability measurements are conducted on 6 shallow (2651–2940 m) and 11 deep (3539–3575 m) Longmaxi samples to obtain the organic geochemical characteristics, mineral constitutions, pore structures and petrophysical properties, and they are the major controls on reservoir quality. The results show similar mineralogical and organic geochemical characteristics in all samples from the various depths. Both shallow and deep shales are mainly composed of quartz, carbonate and clays and have a total organic carbon (TOC) content more than 2 wt.% and a mean S1 + S2 value more than 52 mg/g. Source rock quality criteria using the TOC and S1 + S2 suggest most shale samples fall excellent source rocks. The samples are mostly siliceous rocks that contain organic pores, intraparticle dissolution pores, interparticle quartz pores and interparticle clay pores and they play a positive role in improving reservoir quality. Pore surface area and pore volume increase with increasing TOC, indicating that the porous organic fraction is a major control on pore structure and porosity. We suggested that siliceous deep Longmaxi formation in Weiyuan Block belongs to a high-quality shale with an average TOC value of 3.9 wt.% and well-developed pore networks, which should be the important target for deep shale gas exploration.

Geochemical and paleontological evidence of early Cambrian dynamic ocean oxygenation and its implications for organic matter accumulation in mudrocks at the Three Gorges area, South China

The evolution of global ocean oxygenation during the early Cambrian remains highly controversial, making it difficult to evaluate how environmental triggers play a role in controlling the organic matter (OM) accumulation in black shales. In this study, an integrated approach, including total organic carbon (TOC) content, major and trace element geochemistry, and microscope images, was systematically conducted in a continuous core well that penetrated through the Lower Cambrian Yanjiahe (YJH)–Shuijingtuo (SJT, subdivided into SM Ⅰ, SM Ⅱ, SM Ⅲ, and SM Ⅳ members) successions (∼541-514Ma) at the Three Gorges area, Yangtze Platform, South China. Our results showed that the ocean stepwise oxidation evolution in shelf-slope environments occurred even though the marine redox state showed highly dynamic fluctuations during the early Cambrian. Based on geochemical proxies and sedimentological and faunal criteria, the OM-rich mudrocks in the SJT Formation can be divided into two units. The lower part (SM Ⅰ) contains a higher TOC content (average value 5.71 wt%) than the upper part (SM II, average TOC value of 2.73 wt%). SM Ⅰ are characterized by high MoEF, UEF, Corg/P, and U/Th ratios, indicating that SM I was deposited under constantly euxinic conditions. The relatively declining MoEF, UEF, Corg/P, and U/Th ratios at the transition interval between the SM Ⅰ and SM II records a change in bottom-water to predominantly anoxic conditions with intermittent oxygenation. Correspondingly, the biological record evolved from extremely limited benthic organisms to diverse sponge spicules. The high paleoproductivity, sustained euxinic conditions, and limited dilution linked to sea-level rising are responsible for the OM enrichment in SM I black shales. In comparison, SM II was deposited under mainly suboxic/dysoxic conditions with the lower Corg/P, U/Th ratios, and moderate enrichment of Mo (<25 ppm), which were accompanied by the abundant development of agglutinated benthic foraminifera, sponge spicules, radiolarians, etc. The OM accumulated under low-oxygen conditions and increased terrigenous input even though the paleoproductivity remained at a high level during the deposition of SM Ⅱ. The ocean bottom-water then evolved into oxic conditions with extremely low Corg/P, U/Th ratios, and no Mo concentrations in OM-lean calcareous mudrocks and limestone developed in the upper part of the SJT Formation, including SM Ⅲ (avg. TOC is 0.6 wt%) and SM Ⅳ (avg. TOC is 0.09 wt%). The combination of an oxic depositional environment, limited primary productivity, and dilution of terrigenous inputs was unfavorable for OM enrichment during that period.

Experimental study on reservoir characteristics and oil-bearing properties of Chang 7 lacustrine oil shale in Yan’an area, China

Abstract The Chang 7 Member shale of the Upper Triassic Yanchang formation in the Ordos basin is a hot spot in petroleum geology research. In this study, considering the Chang 7 shale in the Yan’an area as an example, the full-scale pore size characterization of lacustrine shale was realized based on the scanning electron microscopy image gray correction method, nitrogen and carbon dioxide adsorptions, and high-pressure mercury intrusion tests. In addition, the pore structures and oil-bearing properties of the Chang 7 shale were systematically studied. The results show that the Chang 7 shale is rich in organic matter, with an average total organic carbon value of 4.69% and an average R 0 value of 0.9%. It is in the mature-wet gas (crude oil-associated gas) stage. There are certain differences in the development characteristics and pore size distribution of different types of pores in shale. The statistical results showed that the pore diameters of the intergranular pores and intragranular dissolved pores were significantly larger than the intercrystalline pores of clay minerals and the organic pores. The organic pores in solid bitumen are extremely developed, whereas the organic pores in kerogen are relatively underdeveloped. The lower limit of the effective pore size of shale is 20 nm. The network system composed of inorganic pores-microcracks-organic matter-organic pores and siltstone laminae provides important channels and retention spaces for the migration of shale oil and gas within the source. This study found that the proportion of movable oil in sandy layers is relatively high, followed by shale with sandy laminae, whereas pure shale has the lowest proportion of movable oil. Therefore, the degree of sandy laminar development, the abundance of organic matter, and the degree of thermal evolution are the key geological factors that control the porosity and oil-bearing properties of shale oil reservoirs.

Relationship between Organic Geochemistry and Reservoir Characteristics of the Wufeng-Longmaxi Formation Shale in Southeastern Chongqing, SW China

Shale gas accumulates in reservoirs that have favorable characteristics and associated organic geochemistry. The Wufeng-Longmaxi formation of Well Yucan-6 in Southeast Chongqing, SW China was used as a representative example to analyze the organic geochemical and reservoir characteristics of various shale intervals. Total organic carbon (TOC), vitrinite reflectance (Ro), rock pyrolysis, scanning electron microscopy (SEM), and nitrogen adsorption analyses were conducted, and a vertical coupling variation law was established. Results showed the following: the Wufeng-Longmaxi formation shale contains kerogen types I and II2; the average TOC value at the bottom of the formation is 3.04% (and the average value overall is 0.78%); the average Ro value is 1.94%; the organic matter is in a post mature thermal evolutionary stage; the shale minerals are mainly quartz and clay; and the pores are mainly intergranular, intragranular dissolved pores, organic matter pores and micro fractures. In addition, the average specific surface area (BET) of the shale is 5.171 m2/g; micropores account for 4.46% of the total volume; the specific surface area reaches 14.6%; and mesopores and macropores are the main pore spaces. There is a positive correlation between TOC and the quartz content of Wufeng-Longmaxi shale, and porosity is positively correlated with the clay mineral content. It is known that organic pores and the specific area develop more favorably when the clay mineral content is higher because the adsorption capacity is enhanced. In addition, as shale with a high clay mineral content and high TOC content promotes the formation of a large number of nanopores, it has a strong adsorption capacity. Therefore, the most favorable interval for shale gas exploration and development in this well is the shale that has a high TOC content, high clay mineral content, and a suitable quartz content. The findings of this study can help to better identify shale reservoirs and predict the sweet point in shale gas exploration and development.

Geological and Geochemical Characteristics of the First Member of the Cretaceous Qingshankou Formation in the Qijia Sag, Northern Songliao Basin, Northeast China: Implication for Its Shale Oil Enrichment

The Qijia Sag, a secondary tectonic unit in the northern Songliao Basin, developed plentiful shale oil resources in the first member of the Cretaceous Qingshankou Formation (K2qn1) as its main target layer. However, the systematic study on the geological and geochemical characteristics of K2qn1 in the sag has not been carried out. Taking the core samples from the SYY1 well covering the whole K2qn1 as the main study object and concerning some relevant intervals from the SYY1HF well and other earlier wells, petrologic features, organic geochemical characteristics, oil-bearing property, and reservoir characteristics of K2qn1 were analyzed in detail. The results show that the lithology of K2qn1 is mainly dark mudstone genera accounting for more than 90% of the formation thickness with few macrostructural fractures, indicating that K2qn1 developing in deep to semideep lacustrine facies of the Qijia Sag belongs to the typical matrix reservoirs for shale oil. According to lithology features and logging curves, K2qn1 can be divided into three submembers consisting of K2qn11, K2qn12, and K2qn13 from above to below. Compared to the K2qn11 submember, the K2qn12 and K2qn13 submembers obviously are more enriched in shale oil, which is supported by the following three aspects: (i) the average TOC (total organic carbon) values of K2qn11, K2qn12, and K2qn13 are 1.96%, 2.42%, and 2.72%, respectively. The organic matter types of K2qn12 and K2qn13 are mainly type I and type II1, while those of K2qn11 are mainly type II1 and type II2. K2qn1 is at the end of the oil window with a R o (vitrinite reflectance) average of 1.26%, and the maturity of K2qn12 and K2qn13 is slightly higher than that of K2qn11. (ii) The average OSI (oil saturation index) values of K2qn11, K2qn12, and K2qn13 are 110.54 mg/g, 171.74 mg/g, and 150.87 mg/g, respectively, which all reach the zone of oil crossover. The saturated hydrocarbon of EOM (extractable organic matter) in K2qn12 and K2qn13 is of higher content than that in K2qn11, while it is the opposite for the aromatic hydrocarbon, nonhydrocarbon, and asphaltene, indicating better oil mobility for K2qn12 and K2qn13. The average oil saturation values of K2qn11, K2qn12, and K2qn13 are 24.77%, 32.86%, and 35.54%, respectively. (iii) The intragranular dissolution pores and organic pores in K2qn12 and K2qn13 are more developed than those in K2qn11. The average effective porosity values of K2qn11, K2qn12, and K2qn13 interpreted from NMR logging are 4.88%, 6.26%, and 5.86%, respectively. Based on the above-mentioned analyses, the lower K2qn12 and the upper K2qn13 are determined as the best intervals of shale oil enrichment for K2qn1 vertically in the Qijia Sag. There is a certain horizontal heterogeneity of TOC, S 1 , and effective porosity in the drilling horizontal section of K2qn1 of the SYY1HF well. Therefore, the lower K2qn12 and the upper K2qn13 in the area with relatively weak horizontal reservoir heterogeneity of the study area should be selected as the preferential targets for shale oil exploration.

Hydrocarbon generation and expulsion characteristics of the Lower Cambrian Qiongzhusi shale in the Sichuan Basin, Central China: Implications for conventional and unconventional natural gas resource potential

In recent years, significant progress and breakthroughs have been made in the exploration of conventional and unconventional natural gas in the Lower Cambrian petroleum system in the Sichuan Basin in Central China, showing excellent exploration prospects. However, detailed evaluation of the Qiongzhusi shale, the main source rocks in the Lower Cambrian petroleum system, including their hydrocarbon generation and expulsion characteristics, is lacking, even though such evaluation is critical for understanding conventional and unconventional natural gas resource potential. To investigate the geological and geochemical characteristics of the Qiongzhusi shale, experiments including pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) were conducted. Based on modeling work and fluid inclusion analysis, the hydrocarbon generation and expulsion characteristics of the Qiongzhusi shale and their control on hydrocarbon accumulation was analyzed, and the conventional and unconventional natural gas resource potential of the Lower Cambrian petroleum system was systematically evaluated. The results indicate that the organic matter of the Qiongzhusi shale is mainly derived from bacteria and algae deposited in a saline, reducing marine environment. The shale is predominantly composed of type I kerogen with an average TOC value of 1.85 wt%, and is widely distributed in the basin with an average thickness of 212.7 m. The Qiongzhusi shale is primarily post-mature with an average vitrinite reflectance (Ro) of 2.53%. Modeling work suggests the Qiongzhusi shale reached the hydrocarbon expulsion threshold (HET) at Ro = 0.9%, and the main hydrocarbon expulsion stages are Triassic, Jurassic, and Cretaceous. The maximum hydrocarbon generation and expulsion intensities at present day are 32 × 10 6 t/km 2 and 18 × 10 6 t/km 2 , respectively. The conventional natural gas resource potential of the Longwangmiao Formation derived from the Qiongzhusi shale is estimated to be between 9.51 × 10 12 m 3 and 19.03 × 10 12 m 3 . The unconventional shale gas resource potential of the Qiongzhusi shale is predicted to be 1.4 × 10 12 m 3 , showing significant prospects for natural gas exploration. • Geochemistry characteristics of the Qiongzhusi Formation were systemically evaluated. • Hydrocarbon generation and expulsion characteristics of the Qiongzhusi Formation were first analyzed. • Conventional and unconventional natural gas resource potentials of ancient Lower-Cambrian petroleum system were calculated.

Geological characteristics of shale in the Silurian (Sichuan) basin and chemical reaction of its reservoir under the action of fracturing fluid

The exploitation and exploration of shale gas is of great values to solve the energy problem. Taking the shale from Silurian Longmaxi formation in Sichuan Basin as an example, its geological characteristics and reservoir chemical reaction under the action of fracturing fluid were analyzed, and moreover, a series of data determination and fracturing fluid chemical reaction experiments were carried out. The results showed that the average total organic carbon value of shale in the study area was 4.79%, the kerogen type was type I, the ratio of aliphatic structure to aromatic structure was smaller than 1, the average RO value was 2.15%, the content of clay mineral in the mineral composition was high, the average porosity was 3.16%, and the average permeability was 0.036 × 103 μm2, which was conducive to shale gas generation; under the action of fracturing fluid, the sulfate mineral in the shale dissolved, clay mineral expanded, and the pore volume and specific surface area reduced. The results verify that the research area has shale gas mining value, and this study makes some contributions to further study the optimization of fracturing fluid and improve exploitation technology.

Geochemical Analysis for Determining Total Organic Carbon Content Based on ∆LogR Technique in the South Pars Field

There is a recognized need for the determination of total organic carbon (TOC) as an essential factor in the evaluation of source rocks. In this study, the ∆LogR technique was coupled with logging curves of sonic, resistivity, spectral gamma-ray (SGR), and computed gamma-ray (CGR) to determine an accurate content of TOC in the Gadvan Formation. Multiple linear regression analysis was also applied to the ∆LogR technique. To this aim, 14 samples of the Gadvan Formation were taken from Wells B and C in the South Pars field and analyzed using Rock-Eval pyrolysis. Results from the ∆LogR technique and multiple linear regression analysis, well logs, and Rock-Eval were compared to calculate the accurate content of TOC in the Gadvan Formation. Geochemical data confirmed that the Gadvan Formation was a relatively poor source rock in the South Pars field, as average TOC and Tmax values of the samples were 0.79 and less than 430 °C, respectively. Also, the content of potassium (K &lt; 0.1%) confirmed the origin of the source rock as a pure carbonate, whereas the low content of thorium (Th &lt; 5 ppm) was indicative of the percentage of clays. There was a moderate content of uranium (U &lt; 10 ppm), suggesting that the Gadvan Formation was not deposited in an excellent reducing environment to conserve the organic matter. Moreover, the results from the integration of the multiple linear regression model with SGR and CGR showed that the value of R2 was higher than the results obtained without SGR and CGR. Findings from this study could help the exploration and production team to determine the accurate content of TOC using the ∆LogR technique in association with logging curves.

Organic petrography, Rock\u2013Eval pyrolysis and biomarker geochemistry of Maastrichtian Gombe Formation, Gongola Basin, Nigeria

The Maastrichtian Gombe Formation is located within one of the inland basins of Nigeria (Gongola Basin). Surface and borehole samples of coal and interbedded shale of this formation were evaluated to determine the organic matter richness, quality, maturity, source and depositional environment through organic geochemical techniques such as total organic carbon (TOC) determination, Rock–Eval pyrolysis, chromatography and organic petrography. The genetic potential and average TOC value of the coals, shales and coaly shales are 38.03 wt%, 3.14 wt% and 12.1 wt%, respectively, indicating moderate-to-good source potential. HIs are less than 200 mgHC/gTOC for all the samples indicating Type III kerogen for most of the samples (gas prone) and plant contributions from terrestrial sources. The source rocks were characterized by high molecular weight n-alkanes which range from C10–C41 in the coals and C9–C41 in the shales. The n-alkanes distributions in the coals maximize at C29 indicating terrestrial sourced organic matter, while the shales maximize at C16 and C29 indicating mixed sources. Pr/Ph of the coals and shales ranges from (2.15–3.51) to (0.95–2.37), respectively, suggesting fluvio-deltaic deltaic and coastal swamp depositional environments. The predominance of pristane over phytane suggests humic origin of the organic matter. The sterane/hopane values (< 0.6) indicate incorporation of bacterial inputs commonly associated with terrigenous organic matter in the coals. The CPI is greater than unity, Tmax is generally < 435 °C and vitrinite reflectance less than 0.55 Ro for most of the samples and suggest the samples are of low maturity status to expel liquid hydrocarbon.

Geochemical and well logs evaluation of the Triassic source rocks of the Mandawa basin, SE Tanzania: Implication on richness and hydrocarbon generation potential

Selected core and cutting samples from the Triassic succession of the Mbuo claystone and the Nondwa shale were collected from the Mandawa-7, Mbuo-1 and Mbate-1 wells, onshore Mandawa basin, to understand the hydrocarbon generation potential. Earlier studies show that Mbuo claystone and Nondwa shale source rocks have fair to good generation potential based on percent total organic carbon (TOC) with kerogen type II/III, but no detailed studies include the potential for hydrocarbon generation from Triassic source rocks in the Mandawa basin. Detailed parameters like TOC, level of organic maturity (LOM), net to gross (NTG) ratio and integrated geochemical and well log analysis approaches are applied to understand the generation potential of the Triassic source rocks. The results show that TOC derived from well log analysis ranges from 0.01 to 11 wt percent (wt%), clearly including fair to good average TOC values with less than 0.5 NTG for both the Mbuo claystone and the Nondwa shales using a marginal cut-off value of 0.5 wt% TOC. The S1 and S2 values range from 0.1 to 1.7mgHC/g Rock and 1.2–17.2mgHC/g Rock respectively. The cross plot between TOC and S1 and S2 values from Rock Eval shows that these source rocks have low potential for hydrocarbon generation, and that S1 and S2 are independent to the thermal maturity. Integrating results obtained from various studies shows that both Mbuo claystone and Nondwa shales in the Mbate-1 and Mandawa-7 wells have poor hydrocarbon generation potential in their respective organic-rich intervals.

Organic Geochemical Analysis of Shaly Facies from Two Wells Within Anambra Basin, Southeastern Nigeria

Abstract Organic geochemical analysis of two selected wells penetrating shale facies of the Anambra basin was conducted with the view of evaluating the section in terms of quantity and quality of organic matter, genetic potential, organic matter type, thermal maturity as well as determining the type of hydrocarbon that could be generated. Geochemical parameters such as Total Organic Carbon (TOC), S1 (representing free and adsorbed hydrocarbons present), S2 (representing hydrocarbons generated directly from the kerogen), S3 (carbon dioxide CO2 present) and maximum temperature (Tmax) as well as Hydrogen Index (HI), Oxygen Index (OI), Production Index (PI) and Genetic Potential (GP) were derived and calculated from the pyrolysis data. Result indicated that Well 1 samples have an average TOC of 1.21 wt % which is considered good in organic matter quantity and fair in quality, while Well 2 samples are organically lean, poor in quantity and quality with average TOC value of 0.15 wt %. The Genetic Potential (GP) expressed as (S1+S2) for Well 1 and Well 2 averages 2.03 and 0.68 mg HC/g respectively, indicating, a poor generational potential. The HI, OI and S2/S3 values of Well 1 samples are 146.56 mg HC/g, 226.78 mg HC/g and 0.86 respectively which on plots suggest the kerogen as type IV although few samples fall within the type III area. This contrasts with Well 2 samples having HI, OI and S2/S3 values as 343.67 mg HC/g, 276.78 mg HC/g and 1.26 respectively. Thus making the kerogen type to be interpreted as type III. Judging from Tmax (average of 441.67°C for Well 1 and 470.44°C for Well 2) and PI (average of 0.13 for Well 1 and 0.24 for Well 2) values, Well 1 samples are within the oil generating window whereas Well 2 samples are overmatured generating dry gas. Deductions from the result of geochemical analysis show that the kerogen of Well 1 samples will generate oil while that of Well 2 samples have propensity to generate dry gas.

Organic geochemistry and oil-generating potential of the Oligocene–Early Miocene Dingqinghu Formation sediments in the Lunpola Basin, Tibet

The hydrocarbon source rock potential of shales from the Oligocene–Early Miocene Dingqinghu Formation was evaluated using organic geochemistry (Rock-Eval pyrolysis, total organic carbon (TOC) and bitumen extraction) and organic petrology. Forty-one outcrop samples from Lunbori and Jiangria Co shales in the Lunpola Basin were analysed. At Lunbori, in the central part of the basin, the shales have very good source rock potential, and show TOC contents ranging from 3.72 to 11.2 wt%, with an average TOC value of 7.36 wt%, S 2 values of 33.4 – 99.5 mg HC/g rock (average 61.8 mg HC/g rock), and extractable organic matter contents varying from 513 to 4525 ppm (average 2105 ppm). The shales have very good source rock potential. Rock-Eval T max values of 433 – 437°C (average 435°C) and high carbon preference index (CPI) values (4.76 – 6.70) indicate that the organic matter is immature to early mature for oil generation. The yellow fluorescence of kerogen under UV light is in good agreement with T max and CPI data. High hydrogen indices (HI) (635 – 1057 mg HC/g TOC) and H/C ratios (1.60 – 1.72) indicate that the Lunbori shales contain oil-prone organic matter and are characterized by high yellow fluorescing amorphous sapropelite content. The Lunbori shales contain a high content of hydrogen-rich Type II and minor Type I oil-prone kerogen, and have dominant medium to long molecular weight n -alkanes (maximizing at C 25 or C 27 ) with marked odd carbon number preference in the n -C 23 – n -C 31 range, pristine/phytane (Pr/Ph) ratios of 0.06 – 0.14, high phytane/ n -C 18 ratios (10.95 – 30.63), abundant gammacerane (gammacerane/C 31 hopane: 0.44 – 1.80), and predominant regular sterane C 27 . These data indicate deposition in stratified, anoxic and saline depositional conditions with a kerogen predominatly formed from a lacustrine biota. The Jiangria Co shales in the western part of the Lunpola Basin contain some hydrogen-rich Type I and II oil-prone kerogens at a marginally mature level. They have TOC contents of up to 2.62 wt%, S 2 values of up to 17.2 mg HC/g rock and extractable organic matter contents of up to 1731 ppm, indicating good source rock potential for oil generation. This is supported by their high HI values (420 – 720 mg HC/g TOC) and H/C ratios (1.05 – 1.50). The biomarker distributions of the extracts are characterized by odd carbon number predominance (C 23 –C 31 ), low Pr/Ph ratios (0.05 – 0.09), high concentrations of phytane and high gammacerane content, indicating lacustrine reducing and saline conditions.

Organic-geochemistry characterization of the Paleogene to Neogene source rocks in the Sayhut subbasin, Gulf of Aden Basin, with emphasis on organic-matter input and petroleum-generation potential

Paleogene Umm Er Radhuma and Ghaydah and Neogene Sarar source rocks from Sayhut subbasin in the Gulf of Aden Basin were studied to provide information such as organic-matter types, paleoenvironmental conditions, and petroleum-generation potential. This study is based on whole-rock organic-geochemical analyses and organic petrology. The total organic carbon (TOC) contents of the Paleogene to Neogene source rocks range from 0.43% to 6.11%, with an average TOC value of 1.00%, indicating fair to very good source-rock potential. The Paleogene Ghaydah and Umm Er Radhuma source rocks are relatively higher in genetic petroleum potential than Neogene Sarar source rocks. Mainly oil and gas are anticipated from the Ghaydah and Umm Er Radhuma source rocks with hydrogen index (HI) values ranging from 95 to 715 mg hydrocarbon (HC)/g TOC. This is supported by the presence of significant amounts of liptinite macerals in the Ghaydah and Umm Er Radhuma source rocks. The Sarar source rocks are dominated by vitrinitic type III kerogen (HI < 200 mg HC/g TOC) and are thus considered to be gas source rocks. The Paleogene to Neogene source rocks have vitrinite reflectance (R o) values in the range between 0.30% and 0.77% R o, and pyrolysis maximum temperature values range from 412°C to 444°C (774°F to 831°F), consistent with the immature to early mature oil window. Therefore, the present-day kerogen type in the Paleogene to Neogene source rocks is original and should not have been altered by thermal maturity. The biomarker of organic matter suggests that the Paleogene to Neogene source rocks were deposited in a marine environment under suboxic to anoxic conditions. The biomarkers also indicate that the Paleogene to Neogene source rocks contain a mixture of aquatic organic matter (planktonic and bacterial) and terrigenous organic matter, with increasing terrigenous influence to Sarar source-rock samples. Highly hypersaline reducing conditions are also evidenced in Ghaydah and Umm Er Radhuma source rocks, as indicated by the presence of the gammacerane biomarker, low pristane to phytane ratios, and homohopane distribution patterns.

Regional stratigraphy, elemental chemostratigraphy, and organic richness of the Niobrara Member of the Mancos Shale, Piceance Basin, Colorado

The elemental chemostratigraphy of the Upper Cretaceous Niobrara Member of the Mancos Shale shows that six chemostratigraphic zones can be identified in the Piceance Basin, Colorado, based on geochemical data. Chemostratigraphic correlations of nine wells spaced 20 mi (∼32 km) apart closely match lithostratigraphic correlations made using gamma-ray and deep-resistivity wireline logs. Lithologic interpretations made from wireline logs indicate that the Niobrara Member and equivalent strata consist primarily of interbedded calcareous shale and shaley limestone facies that increase in thickness to the northwest in the basin. The geochemical data suggest that during deposition of the Niobrara Member, anoxia and calcium enrichment increased to the east of the basin, whereas terrestrial input and clay enrichment increased to the northwest. Element crossplots suggest that a large part of the silicon is detrital and that the Niobrara Member becomes an increasingly more clastic than carbonate system to the west and northwest. The Δlog R–derived total organic carbon (TOC) calculated using a sonic-resistivity overlay analysis technique shows that the Niobrara Member comprises organic-rich and organic-poor deposits. Average TOC values range between 1 wt. % (in organic-poor deposits) and 2.37 wt. % (in organic-rich deposits), with higher TOC values recorded in the southern and eastern parts of the basin. Relative-rock brittleness estimates from element and TOC data show the stratigraphic variability of alternating ductile (TOC rich, Ca and Si/Al poor) and brittle (TOC poor, Ca and Si/Al rich) intervals for the Niobrara Member.