Organic Richness Research Articles

The Birkhead and Murta formations—organic geochemistry and organic petrography of Mesozoic fluvio-lacustrine source rocks in the Eromanga Basin, central Australia

Due to a historic focus on the underlying Cooper Basin and a growing demand for energy in Australia, a reassessment of the Eromanga Basin in central and eastern Australia is necessary, including a more detailed characterization of its Jurassic-Cretaceous petroleum system elements. The Jurassic Birkhead Formation and the Cretaceous Murta Formation are considered the most important source rocks of the Eromanga Basin. To study the petroleum generation potential of these two formations, a set of 55 rock cores from eight petroleum exploration wells was analysed. The sample set was subject to multiple-organic geochemical and petrographical analyses to evaluate organic richness, hydrocarbon potential (Rock–Eval S1 and S2), maceral composition, thermal maturity (e.g. vitrinite reflectance), and saturated and aromatic biomarker composition. The investigated fluvio-lacustrine siltstones and carbonaceous shales exhibit low to excellent total organic carbon (TOC) content, very low sulphur and low inorganic carbon content. Thermal maturity of both formations is at the onset of the oil window (immature to early mature). The Cretaceous Murta Formation shows good hydrocarbon generation potential and, in part, high production indices, while the Jurassic Birkhead Formation generally shows low kerogen to bitumen conversion and a good to very good hydrocarbon generation potential. Dispersed, rather coarse organic matter of terrigenous origin in fine-grained siliciclastic matrix with well-preserved plant remnants including “cutinite flames” is typical. Liptinite (mainly lamalginite) content is generally higher in the Murta Formation (including the occurrence of Botryococcus green algae), while vitrinite is clearly dominant in the Birkhead Formation. The Birkhead solvent extracts exhibit a more heterogeneous distribution of n-alkanes with distinct maxima in the long-chain range, whereas shorter-chain n-alkanes dominate the Murta extracts. Based on their quality and quantity of incorporated organic matter as well as thermal maturity, the petroleum generation potential of the Murta and Birkhead formations is discussed in detail.

An integrated source rock potential, sequence stratigraphy, and petroleum geology of (Agbada-Akata) sediment succession, Niger delta: application of well logs aided by 3D seismic and basin modeling

We investigated the source rock potential, sequence stratigraphy, and characterized hydrocarbon reservoirs at Otumara field, Niger delta, using integrated 3D seismic, wireline log analysis, and basin modeling. The burial history and thermal maturity were modeled, the reservoirs were delineated, and the petrophysical parameters were also estimated from the wireline logs. The Passey “ΔLog R” method for estimating the preliminary evaluations of the total organic carbon (TOC) from integrating sonic, neutron, and density with resistivity has been used. The results indicate that the primary source rock of hydrocarbons is the Upper Akata Formation, despite a higher TOC percentage in the Agbada Formation. Based on sequence stratigraphy analysis, TA4, TB1, TB2, and TB3 second-order supercycles were obtained in the studied well TD46. The results also revealed that the field has two large net pays with high-quality reservoir facies: a deltaic slope fan at the upper shoreface and a river mouth sandbar at the lower shoreface. Furthermore, the reservoirs were faulted by a series of growing faults that faulted the basin slope. The reservoir facies are characterized by an average of 18% porosity, 1200 mD permeability, 16% volume of shale, and high hydrocarbon saturation of about 85%. Finally, the petroleum system elements have been defined for improved hydrocarbon exploration. In the absence of complete or partial core samples, this case study emphasizes the importance of using wireline logs to estimate organic richness and investigate sequence stratigraphy in clastic sediments.

Organic geochemistry and petrology of source rocks from the Banqiao Sag, Bohai Bay Basin, China: Implications for petroleum exploration

The organic geochemistry and petrology of source rocks determine the hydrocarbon generation potential of the Banqiao Sag. In this study, organic geochemistry and petrology were used to determine the abundance of organic matter (OM), OM type, OM maturity, and sedimentary environments of the source rocks, collected from Cenozoic Shahejie Formation, Banqiao Sag, Bohai Bay Basin, China. Vitrinite and liptinite are the main maceral composition of the source rocks, and range from 18% to 81% and from 2% to 82% on a mineral matter free (MMF) basis, respectively. The values of vitrinite reflectance ( R o ) (0.36%–1.20%) and the T max values (397–486 °C) show that the thermal maturity range from low mature to peak-maturity. The abundance of OM varies between 0.22% and 4.37%, suggesting that the source rocks of the Shahejie (Es) Formation are mainly fair to good source rocks. The Rock-Eval pyrolysis results show that the source rocks have good petroleum generation potential. The amount of free hydrocarbons ( S 1 ) and hydrocarbons generated from pyrolysis ( S 2 ) range within 0.01–3.70 mg/g, and 0.04–29.17 mg/g. The hydrogen index (HI) varies between 18.18 and 741.13 mg HC/g TOC, with most of the samples appearing to be mainly Type II kerogen, and thereby exhibiting the ability to generate both oil and gas. The ratios of Pr/Ph, the cross plot of Pr/nC 17 –Ph/nC 18 , the cross plot of C 29 /C 27 –Pr/Ph, and ternary of dibenzothiophene, dibenzofuran, and fluorene, indicate that the Shahejie Formation deposited in suboxic and weak reducing environments. The main biological source is from advanced plants. The maceral composition and rock pyrolysis data indicate the kerogen type is a humic type or mixed sapropelic-humic type. The source rocks of the Shahejie (Es) Formation occur in the oil window, and the abundant organic richness, humic kerogen demonstrate that these rocks are effective oil and gas source rocks. The mudstone rocks in the Shahejie Formation are the main source of oil and gas and represent the main exploration target for the Banqiao Sag. This study enhances the great prospect of oil and gas production in the Banqiao Sag.

An integrated geochemical analysis, basin modeling, and palynofacies analysis for characterizing mixed organic-rich carbonate and shale rocks in Mesopotamian Basin, Iraq: Insights for multisource rocks evaluation

Shales and carbonate-rich sediments are crucial in characterizing the geological history of petroleum as source rocks. This emphasizes the global significance of carbonate source rocks, and it has sparked research interests and exploration of these strata as unconventional resources. This study presents inclusive organic geochemical characteristics, palynofacies analysis, and basin modeling of the carbonate source rocks in the Ajeel oilfield, Mesopotamian Basin, Iraq. This study used traditional and advanced geochemical techniques, as well as microscopic examination and basin modeling. A total of 109 core and cutting samples from the Middle Jurassic–lowermost Early Cretaceous succession were studied via geochemical and palynological methods to evaluate their thermal maturation, depositional conditions, and hydrocarbon (HC) generation potential by combining one-dimensional (1D) modeling of the burial/thermal history and the generation/expulsion timing in the Mesopotamian Basin, Iraq. The results of total organic carbon/Rock-Eval pyrolysis revealed that the Middle Jurassic–lowermost Early Cretaceous interval predominantly comprised carbonate-rich sediments with Type-II and mixed Type-II/III kerogen. Furthermore, the results showed that these potential source rocks were of fair to excellent quality (oil window) and were deposited mainly in an anoxic marine environment. Geochemical and palynological investigation suggested that the carbonate-rich source rocks were deposited mainly under a distal suboxic–anoxic condition and contained Type-II kerogen (oil prone), except for part of the Chia Gara Formation, which displayed distal dysoxic–oxic shelf depositional conditions. The 1D basin modeling results of the burial/thermal maturation history and the generation/expulsion timing showed that these sediments reached their peak generation potential (main oil window) during the Early Miocene, and this has continued until the present day. Subsequently, the Middle Jurassic–lowermost Early Cretaceous succession represents the main source of petroleum in the Mesopotamian Basin, Iraq.This work shows how an integrated palynofacies analysis, basin modeling, and geochemical study can be used for the precise assessment of multisource rock intervals of mixed organic-rich carbonate and shale rocks. These research findings will provide guidance for better resource exploitation in northern Iraq, which has higher source-rock quality in terms of organic richness and maturity than that in southern Iraq.

Macrobenthic Assemblages, Distribution and Functional Guilds from a Freshwater-Dominated Tropical Estuary

Assessment of benthic diversity and estuarine ecological quality is becoming increasingly important. Estuaries are not only highly productive and variable environments, but they are also areas of high anthropogenic perturbations. In this study, benthic macrofauna were sorted, identified and analyzed from a freshwater-dominated tropical estuary along the Bay of Bengal to assess their community structure, distribution and functional guilds, and to uncover the environmental drivers influencing their distributional patterns. Results revealed that the studied physio-chemical variables (DO, pH, alkalinity and temperature) were significantly varied (p < 0.05) among the sites. Capitella sp. was dominant (18%) of the forty morphospecies recorded, indicating organic richness of the area. The ANOVA results revealed that macrobenthic density differed significantly (p < 0.01) between the study locations, and diversity indices (Shannon diversity index, H′) also differed significantly (F4,12 = 5.89; p = 0.02). The benthic density decreased from the head to the mouth, which could be related to salinity fluctuations and large freshwater discharges. Upstream sites were completely segregated from downstream and mid-estuarine sites, according to cluster analysis (CA). The SIMPER results clarified the site grouping pattern, showing that Mysis-1 spp., Capitella spp. and Nephtys-1 were the most significant contributors. From the communities, five functional trophic groups were identified where deposit feeders were the most dominant (66.44%). Most of the macrobenthos had strong positive correlations with DO (r = 0.92) and water temperature (r = 0.86) and a negative correlation with soil pH (r = −0.28), per correlation and CCA analyses. Individually, soil pH (r = 0.88) and alkalinity (r = 0.898) showed strong positive correlation with Capitella sp. and Chironomus sp.2. The above results indicate that macrobenthos of this estuary do not follow the usual pattern of spatial distribution, and they are structured by DO, alkalinity and soil pH. In addition, dominance of some pollution indicator species (Capitella sp. and Chironomus sp.) and deposit feeders indicates a poor ecological condition of the estuary.

Hydrocarbon Potential and Biomarker Studies of EE-1 Well, Offshore Eastern Dahomey Basin, SW Nigeria

Abstract The hydrocarbon potential, organic source input, and paleodepositional environment of subsurface sediments from EE-1 well, offshore Eastern Dahomey Basin, were assessed using Rock-Eval pyrolysis and biomarker geochemistry. The total organic carbon (TOC) and soluble organic matter (SOM) in the sediments ranged from 0.96wt% to 8.92wt% and 676.12 ppm to 2883.85 ppm, respectively, indicating adequate to excellent organic richness. The pseudo-Van Krevelen plot classified the sediments as types II and III kerogen, which have the potential to generate both oil and gas. The Tmax and production index (PI) ranged from 422°C to 431°C (average, 426°C) and 0.03 to 0.24, respectively, suggesting low thermal maturity. The presence of C27–C29 steranes, oleanane, and hopane/sterane ratio (1.53/16.11), indicated organic matter from mixed sources with more terrigenous input. Cross plots of Pr/nC17 against Ph/nC18, C35/C31 – C35 homohopane index (0.05 – 0.17) and other related biomarker ratios such as C21/C23 trycyclic terpane ratio (0.33 – 0.82) signified that the sediments were deposited in mixed marine/terrigenous environment under oxic – suboxic conditions. This study has demonstrated that sediments had adequate organic matter with the potential to generate both oil and gas at appropriate thermal maturity.

Source Rock Evaluation of Shale in Parts of Ini Local Government Area, Akwa Ibom State, Southeastern Niger Delta Basin, Nigeria

Total organic carbon and Rock – Eval pyrolysis studies were conducted on seven (7) shale samples outcropping in parts of Ini Local Government Area of Akwa Ibom State, Southeastern Niger Delta, Nigeria. The studies were done to determine the quantity and quality of organic matter in the shale source rock, and their hydrocarbon generation potential. Total organic carbon (TOC) values indicate poor to excellent organic richness with values ranging from 0.46 wt.% to 5.98 wt.%. The free oil content (S1) values range from 0.02-0.21 mg HC/g rock, (mean = 0.07 mg HC/g rock), while the source rock potential (S2) ranges from 0.08-1.09 mg HC/g rock with an average value of 0.45 mg HC/g rock both indicating poor source rock generative potential. The Hydrogen Index (HI) and the Oxygen Index (OI) range from 11 mg HC/g TOC to 59 mg HC/g TOC and 41 mg CO/g TOC to 74 mg CO/g TOC with an average value of 27.28 mg HC/g TOC and 55.71 mg CO/g TOC respectively. HI versus OI and S2 versus TOC cross plot results indicate that shale in parts of Ini Local Government Area contains organic matter capable of generating kerogen type III to type 1V which is gas prone.

Depositional setting and organic matter characterization of the Upper Devonian Antrim Shale, Michigan Basin: Implications for hydrocarbon potential

During the Late Devonian, the Michigan Basin in the Eastern Interior Seaway was characterized by phases of well-developed bottom water anoxia, triggering extensive accumulation of organic matter-rich black shales. Palynological analysis for paleoenvironmental reconstruction and biostratigraphy of the Upper Devonian rocks has been previously performed in other basins of eastern North America, but it is lacking in the Michigan Basin. Here, the Upper Devonian Antrim Shale Formation is investigated for biostratigraphic, paleoenvironmental, and sea level reconstructions, organic matter characterization, and source rock potential. 35 core samples from three drill holes across the Michigan Basin spanning the Norwood, Paxton, Lachine, and Upper members. Palynological analysis showed a moderately diverse assemblage of 31 genera represented by 53 species of relatively well-preserved prasinophyte phycomata and acritarchs, with sparse records of plant spores and freshwater algae. Based on marker prasinophytes and acritarchs, an age of late Frasnian was assigned to the Norwood and Paxton members, while an early Famennian age was proposed to the Lachine and Upper members of the Antrim Shale. Two palynofacies assemblages (PFA) were identified from the variation in the particulate organic matter (POM) composition, both of which indicate deposition in a distal inner neritic shelf environment, but the PFA-2 took place in slightly shallower conditions than the PFA-1. Geochemical screening indicated high organic matter content (up to 25 wt%, avg. 8.5 wt%) and excellent hydrocarbon generating potential of kerogen Type II for the Norwood, Lachine, and Upper members. Only the Paxton Member was dominated by poor to fair organic richness (<0.6 wt%) and low hydrocarbon potential with a mixed Type II/III kerogen. Organic petrography indicated that the dominant organic matter assemblage consists mainly of unicellular marine Tasmanites telalginite and Leiosphaeridia, followed by solid bitumen of the initial oil type. Thermal maturity, determined from VRo-eq and Tmax, indicated that all samples are in the oil window, except for some intervals in the Paxton Member.

Elastic properties and pore structure characterization of selected shales in the sungai Perlis beds, Terengganu, Peninsular Malaysia

Studied drill core of the Sungai Perlis Beds in the Terengganu State, Peninsular Malaysia, consists of a diverse suite of organic rich shale lithofacies at various subsurface depths. Lithofacies were delineated on the basis bedding thickness, mineralogy, and organic richness carried out by X-ray diffraction and (XRD) total organic content (TOC) analysis. Field-emission scanning electron microscopy (FE-SEM) analysis was carried out to identify the pore structure, range of pore sizes and mineral arrangement within each lithofacies unit Elastic geomechanical properties (Young’s modulus and Poisson’s ratio) were measured on core samples from each lithofacies unit using static and dynamic approaches. The identified lithofacies include moderate TOC massive argillaceous shale (MTOCMAS), high TOC massive argillaceous shale (HTOCMAS) and high TOC massive siliceous shale (HTOCMSS). FE-SEM analysis shows that pores in all the lithofacies are mostly intergranular, associated with phyllosilicate minerals, and ranges from <1 micrometer to approximately 8 micrometer. Static and dynamic elastic properties measurement shows that shale lithofacies having a high content of phyllosilicate minerals has a lower Young’s modulus and a high Poisson’s ratio value while lithofacies rich in brittle minerals has a higher Young’s modulus and a low Poisson’s ratio value. A good correlation exists between mineralogical brittleness index of the lithofacies and their plane strain modulus. The plane strain modulus is found higher in lithofacies having abundance of brittle minerals in the matrix suggesting that the high TOC massive siliceous shale (HTOCMSS) would preferably allow formation of dense hydraulic fractures, as observed in the CT scan analysis of triaxially fractured specimen, compared to argillaceous shale lithofacies.

Mineralogy, Organic Richness and Macerated Microbial Studies of the Rohtasgarh Shales in the Vindhyan Basin, India: Implications for Gas Generation Potential

Abstract The Proterozoic black shales of Rohtas Subgroup in Vindhyan basin are analyzed to assess their hydrocarbon generation potential. A total of 50 core samples of shales and limestones were collected from borehole core of Rohtasgarh limestone in Amehta mine, Vindhyan basin located in Katni district, Madhya Pradesh. The petrographic analysis, X-Ray diffraction, rock eval pyrolysis and maceral studies were carried out on separated black shales from the carbonates. The study presents that the Rohtas Subgroup of Semri Group consists of greyish to black limestone, greyish to greyish black shales, calcareous shales, silicified shales, pyritic shales and dark black shales alterations with limestones. XRD study reveals the presence of quartz (23.4%), plagioclase feldspar (21.9%), siderite (10.9%), aragonite (2.93%), calcite(1.9%), hematite (4.23%), illite (1.27%), kaolinite (3.2%), pyrite (3.86%), dolomite (8.2%), chlorite (2.43%), gypsum (4.02%), albite (3.4%), potassium feldspar (1.9%) in the samples, where smectite is dominating clay and feldspar in the form of potassium and plagioclase feldspar is the chief constituent among the detrital framework grains. The total organic content (TOC) of the shale units ranges from 0.22 wt. % to 1.08 wt.%, whereas hydrogen index (HI) ranges from 11 to 90 mg HC/g TOC, oxygen index (OI) ranges from 1.08 to 31.82 mg CO2/gTOC, Tmax ranges from 431 to 525°C, production index (PI) ranges from 0.11-1.0. Unstructured organic matters are extracted through maceration techniques, which infer thermal maturity stages of the shales. The dark brown to black in colour of the studied palynomorphs extracted from the Rohtasgarh shales inferred strong thermal alternation of the source rock over geological time. High thermal alteration index (TAI) of Rohtasgarh shales (3.5) suggests the presence of post maturated organic matters with gas prone type III &amp; IV kerogen. The organic richness, kerogen type, thermal maturity of Rohtasgarh limestone in the study area signify poor to fair hydrocarbon generation potential.

Lithofacies characterization and source rock assessment of the lower-middle Miocene Successions in the northern part of Ramadan oil field, central Gulf of Suez, Egypt

Facies of rifting basins reflect different depositional environments from deep to shallow conditions. The present study focuses on subsurface facies characterization and source rock assessment of Kareem and Rudeis rocks in six wells lying in the central Gulf of Suez. The distribution of the lithologic patterns delineated through several constructed facies maps. Porosity cross-plots of Kareem and Rudeis formations to determine the rock minerals and porosity attitudes. Rock–Eval pyrolysis was applied to determine the kerogen type, organic matter richness, percentage, and maturation of the source rocks. The greater depth of the two formations was reflected in the western parts while their stratigraphic thickness increases toward the east and the north directions, with decreasing thickness towards the west direction due to an underlain basin structure of the pre-Miocene. Isolith maps show three deep marine lithologies for the two formations with the anhydrite as a fourth shallow marine lithology in the Kareem Formation only. These lithofacies reflect the turnover from the deep to the shallow depositional environment. The facies change from a main shaly limestone in the Rudeis Formation to calcareous shale in the Kareem formation, indicating transmutation from the lower Miocene deep to the middle Miocene shallow marine environments. The cross-plots reflected the existence of limestone, shale, and anhydrite. Geochemically, both formations are marginally good source rock with a marginally good generation of mixed type II/III and type III. Accordingly, Rudeis and Kareem formations could be good reservoirs rather than being potential source rocks in the central Gulf of Suez.

Integrated organic geochemical/petrographic and well logging analyses to evaluate the hydrocarbon source rock potential of the Middle Jurassic upper Khatatba Formation in Matruh Basin, northwestern Egypt

The present national and international pursuit of converting Egypt into a regional hub of natural gas in the East Mediterranean region resulted in conducting extensive exploration activities in several areas of northern Egypt. Therefore, organic petrographic, geochemical, and geophysical analyses were carried out on the upper Khatatba Formation from the OBA 2-2A well in the Matruh Basin.Restoration of the original sedimentological and geochemical characteristics of the upper Khatatba Formation suggest deposition of this formation in deltaic settings. Few shale and partly calcareous shale units of the Upper Safa and the uppermost Zahra members accumulated in TST in prodelta settings under dysoxic-anoxic conditions. These shale units had an original gas/oil-prone organic facies BC. Other shales and partly calcareous shales of the Upper Safa and Zahra members accumulated in HST in deltafront settings under relatively oxic conditions and had an original lower gas-prone organic facies C.The Upper Safa Member had an original active fair to excellent organic richness (0.76–7.35, avg. 3.38 TOCo(live) wt%) and hydrocarbon source rock potential (S2o: 2.22–17.97, avg. 8.05 mg HC/g org. C). It was characterised mainly by original active mixed gas/oil-prone kerogen type IIIo(live)-IIo(live) (HIo(live): 200.27–297.34, avg. 238.03 mg HC/g TOCo(live)) and subordinately by gas-prone kerogen type IIIo(live) (HIo(live): 181.50 mg HC/g TOCo(live)). The Upper Safa Member had original poor to fair proportions of active oil-prone (0.15–1.47, avg 0.68 TOCo(live, oil) wt%) and higher fair to very good proportions of active gas-prone (0.61–5.88, avg. 2.70 TOCo(live, gas) wt%) kerogens. The Upper Safa Member originally possessed poor to very good oil (S2o(oil): 0.44–3.59, avg. 1.16 mg HC/g org. C) and good to very good gas (S2o(gas): 1.77–14.37, avg. 6.44 mg HC/g org. C) generation potential. The carbonates and partly calcareous shales of the uppermost Safa and the Zahra members possessed poor oil and gas generation potential due to their organic-lean status.The present-day organic geochemical characterization indicates that the Upper Safa Member still shows active fair to excellent organic richness (0.68–6.75, avg. 3.11 TOCpd(live) wt%). However, this member shows a relatively lower present-day good to very good/excellent source rock potential (S2pd: 1.33–10.78, avg. 4.83 mg HC/g rock) and lower active kerogen quality IIIpd(live) (HIpd(live): 115.97–198.21, avg. 151.07 mg HC/g TOCpd(live)). This is related to the current high thermal maturation (gas-window: Tmax: 459–468, avg. 469 °C, thermal alteration index: TAI of 4-) and conversion of the original kerogen IIIo(live)-IIo(live) into oil and gas. The present-day high organic richness, high remaining generative potential, high shale volume of the thermally mature gas-prone kerogen, classify the Upper Safa Member as an active fair to excellent shale gas play in the Matruh Basin. Intrabasinal and interbasinal correlations across northwestern Egypt indicate that the upper Khatatba Formation shows locally and regionally dual source and reservoir rock characteristics due to the lateral facies changes.

An evaluation of Maastrichtian-Paleocene source rock interval on the western flank of Niger Delta Basin, Nigeria: Implications for hydrocarbon prospectivity

Maastrichtian and Paleocene shales recovered from a vertical exploratory well on the western flank of Niger Delta Basin, close to the boundary of the Dahomey (Benin) Basin, were studied for their possible contribution to the hydrocarbon potential of the basin. The organic matter richness, kerogen types, and thermal maturity of the studied shale samples and implications of hydrocarbon generation potential were determined based on results of TOC/Rock-Eval analysis. The Maastrichtian and Paleocene shale samples are characterized by total organic carbon (TOC) values of up to 4.70 wt. % and S2 (hydrocarbon-generating potential) values range from 0.68 to 2.69 mgHC/g rock, indicating poor to fair source potential. The presence of type III and type IV kerogen is indicative of poor-quality organic matter that has the potential to generate gaseous hydrocarbon. This study suggests that the Maastrichtian and Paleocene source rocks on the western flank of the Niger Delta Basin are immature to early mature stage, and could not have generated a commercial amount of hydrocarbon.

Hydrocarbon source rock assessment of the shale and coal bearing horizons of the Early Paleocene Hangu Formation in Kala-Chitta Range, Northwest Pakistan

The present study aims to investigate the origin, type, thermal maturity and hydrocarbon generation potential of organic matter and paleo-depositional environment of the Early Paleocene (Danian) Hangu Formation outcropped in the Kala-Chitta Range of Northwest Pakistan, Eastern Tethys. Organic-rich shale and coal intervals were utilized for geochemical analyses including TOC (total organic carbon) and Rock–Eval pyrolysis coupled with carbon (δ13Corg) and nitrogen (δ15Norg) stable isotopes. The organic geochemical results showed that the kerogen Type II (oil/gas prone) and Type III (gas prone) dominate the investigated rock units. The TOC (wt%) and S2 yield indicate that the rock unit quantifies sufficient organic matter (OM) to act as potential source rock. However, the thermal maturity Tmax°C marks the over maturation of the OM, which may be possibly linked with the effect attained from nearby tectonically active Himalayan Foreland Fold-and-Thrust Belt system and associated metamorphosed sequences. The organic geochemical analyses deciphered indigenous nature of the OM and resultant hydrocarbons. The δ13Corg and δ15Norg stable isotopic signatures illustrated enrichment of the OM from both marine and terrestrial sources accumulated into the Hangu Formation. The Paleo-depositional model established using organic geochemical and stable isotopic data for the formation supports its deposition in a shallow marine proximal inner shelf environment with prevalence of sub-oxic to anoxic conditions, a scenario that could enhance the OM preservation. Overall, the formation holds promising coal and shale intervals in terms of organic richness, but due to relatively over thermal maturation, it cannot act as an effective source rock for liquid hydrocarbon generation and only minor amount of dry gas can be expected. In implication, the results of this study suggest least prospects of liquid hydrocarbon generation potential within Hangu Formation at studied sections.

Integrated sedimentary and high-resolution mineralogical characterisation of Ordovician shale from Canning Basin, Western Australia: Implications for facies heterogeneity evaluation

An understanding of the nature of the facies heterogeneity is crucial for successful exploration and development of shale reservoirs. However, shale is a very fine-grained sedimentary rock and it is challenging to understand its heterogeneity through conventional techniques. This paper addresses this challenge for Ordovician Goldwyer Formation (Goldwyer-III shale) through a unique approach by integrating core data with high-resolution image logs (SCMI); petrographic information; Fourier transform infrared (FTIR); and hyperspectral drill core reflectance spectra acquired using a HyLogger3. The petrographic and FTIR data validates the usage of HyLogger3 as a tool to examine high-resolution vertical variations in the shale mineralogy. The results indicate that the Goldwyer-III shale is highly heterogeneous in terms of sedimentary features, organic richness and mineral composition. The studied shale is divided into four facies based on colour, sedimentary features, mineral composition and lithology. The facies include thinly laminated siliceous shale (TLSh), concretionary-banded calcareous shale (CSh), massive black shale (MBSh) and heterolithic shale (HSh). The total organic carbon varies from 0.35 to 4.5 wt% due to variation in facies as a result of fluctuation in oxic-anoxic conditions. The TLSh, MBSh and HSh facies have a higher TOC value (up to 4.5 wt %), T max (up to 450 °C), hydrogen index (up to 250 mgHC/g) and brittleness index (>0.4) comparatively. Whereas, the CSh facies has least TOC, Tmax, hydrogen index and brittleness index. Continuous high-resolution hyperspectral core log data, combined with petrography and conventional core logging, provides a much better understanding of heterogeneity in Goldwyer-III shale. This study offers a new workflow for rapid, continuous and accurate recognition of optimum facies for hydraulic fracturing. This approach can improve economic decisions when developing shale gas reservoirs. Based on TOC and mineralogical derived brittleness index cut-offs values, the high-quality brittle zones are recognised in TLSh and HSh facies deposited in medial (proximal to distal) depositional setting. • The marine shale is highly heterogeneous even at μm scale. • The integration of high resolution data provided a unique workflow for facies classification scheme in shale. • A continuous vertical facies heterogeneity is obtained. • HyLogger3 data with petrography and FTIR is validated for shale. • The influence of depositional setting on shale reservoir potential is discussed.

Comprehensive 3D reservoir modelling and basin analysis: An insight into petroleum geology to re‐evaluate the hydrocarbon possibilities in the Siwa Basin, North‐Western Desert, Egypt

Three‐dimensional (3D) reservoir modelling and basin analysis were performed for the Siwa Basin in the North‐Western Desert of Egypt. An integrative study from the available data were done, including geochemical data to construct a 1D basin model, petrophysical data to realize the characteristics of the reservoir, and geological data to understand the subsurface geologic setting, has been undertaken. Basin modelling was done for the Siwa A1‐X well to determine the burial and thermal history, sedimentation rate, level of maturity, and finally the event chart for the petroleum system. Siwa Basin comprises one petroleum system. The source rock is represented by the Palaeozoic Dhiffah, Desouky, and Zeitoun formations, with fair to good organic richness, producing oil and gas, which entered the oil window in 143.91, 162.87, and 167.31 Ma, and entered the wet gas in 138.75, 141.82, and 143.63 Ma, with sedimentation rate varying from low to high 543.96, 22.79, and 1,404.46 m/Ma, respectively. The Safa Member (Khatatba Formation) is the main reservoir, with hydrocarbon saturation reaching up to 80%, and with a low subsidence rate of 76.43 m/Ma. The Original Oil In Place for the new prospects is 197.177 Stock Tank Barrel (STB), while for the oil reserve is 50.618 Stock Tank Barrel (STB).

Sedimentological, petrophysical, and geochemical controls on deep marine unconventional tight limestone and dolostone reservoir: Insights from the Cenomanian/Turonian oceanic anoxic event 2 organic-rich sediments, southeast Constantine Basin, Algeria

The Cenomanian/Turonian period is characterized by the deposition of organic-rich and fine-grained sediments that form important source rocks and unconventional reservoir units in North Africa and other parts of the world. The Lower Turonian deposits of the Djebel Darmoun Field, southeast Constantine Basin, Algeria, comprise a thick carbonate succession that has potential as an unconventional reservoir unit. This research aims to investigate the Lower Turonian succession in terms of microfacies, diagenesis, petrophysical, and geochemical characteristics, which were previously unknown. Sedimentological and diagenesis analyses were performed based on the core and thin section observations. Furthermore, geochemical and petrophysical analysis methods were carried out to assess the resource potential based on geochemical measurements, core measurements, and well logging evaluation in an arrangement. Based on sedimentological investigation, the Lower Turonian carbonate section is composed of tight limestone and dolostone rocks characterized by four bioclastic limestones and two dolomicrite microfacies, while paleontological investigation indicates that the faunal content is dominated by planktonic assemblages, revealing a pelagic deep marine setting environment. The primary pores of the Lower Turonian carbonate rocks are seldom preserved due to multi-stage diagenetic alteration (i.e., cementation, compaction, fracturing, dolomitization, dissolution, asphaltene), while dominant secondary pores are represented by dissolution-enlarged and open fractures/fissures, while intercrystal pores might be added in dolostone intervals. Dissolution and fracturing diagenetic events play a major role in enhancing the pore network, while compaction, cementation, and asphaltene diagenesis processes share in the obliteration of the petrophysical properties. Dolomitization played a dual role in the dolostone intervals, where it tended to develop the porosity at the early stages of diagenesis, while it tended to decrease the porosity at the latest diagenesis stages. The geochemical analysis indicated high amounts of organic matter in these intervals, where the higher estimated organic richness reaches a maximum TOC of 7.8% at the lowermost part. The petrophysical analysis inferred that the Lower Turonian carbonate sediments are characterized by low porosity (avg. 4%), very low permeability (<0.01mD), with dominant micro and meso porosities, and therefore they can be classified as tight carbonate unconventional resources. This study provides an insight into factors controlling the pore system network (microporosity) of fine-grained carbonate rocks as an excellent analog of the deep marine unconventional tight limestone and dolostone reservoirs and improves the knowledge and modeling of these unconventional resources. The study sheds light on the organic-rich sediments that are associated with oceanic anoxic events (OAEs) across the North African region and other parts elsewhere, forming high quality source rocks that might be neglected as excellent unconventional resources.

Statistical Modelling for the Source Rock Parameters of the Montney Formation, NE British Columbia, Canada

Hydrocarbons in self-sourced reservoirs are determined by the concentration and maturation of organic matter in sediments. As a result, lowering risk in unconventional resource research and development requires knowledge of hydrocarbon potentiality factors. The geochemical data for the Montney Formation samples studied suggest that it is a fair to good source rock with type IV kerogen that can generate gas in general. The statistical modelling of the analyzed data reveals a valuable technique for identifying characteristics, clusters, and linkages that affect source rock assessment. The Spearman’s correlation coefficient showed a good positive correlation between the total organic carbon (TOC) and free hydrocarbons (S1), generating potential (S2), and potential yield (GP). There was a weak correlation with the maturity index (Tmax) and hydrogen index (HI) and a highly negative correlation between the TOC and oxygen index (OI). On the other hand, the principal component analysis (PCA) showed the presence of three factors affecting the source rock evaluation. Factor 1 included TOC, S1, and S2, which are related to organic richness and hydrocarbon potentiality; factor 2 contained the production index (PI), and the generated CO2 (S3) was related to the organic matter source. Factor 3 included the Tmax and HI related to the type of organic matter and thermal maturity. In addition, the TwoStep cluster analysis separated the source rock in the study area into two major groups. Cluster 1 is characterized relatively by high HI, TOC, S1, S2, and PI, with Tmax &lt; 455 °C indicating good source rock in the mature level with the capability to generate little oil and condensate gas. Cluster 2 is characterized by relatively low HI, TOC, S1, S2, and PI, with Tmax &gt; 455 °C, indicating an over-mature source rock in the dry gas window.

Multimineral petrophysics of thermally immature Eagle Ford Group and Cretaceous mudstones, U.S. Geological Survey Gulf Coast 1 research wellbore in central Texas

Traditional petrophysical methods to evaluate organic richness and mineralogy using gamma-ray and resistivity log responses are not diagnostic in source rocks. We have developed a deterministic, nonproprietary method to quantify formation variability in total organic carbon (TOC) and three key mudrock mineralogical components of nonhydrocarbon-bearing source rock strata of the Eagle Ford Group by developing a set of log-derived multimineral models calibrated with Fourier transform infrared spectroscopy core data from the research borehole U.S. Geological Survey Gulf Coast 1 West Woodway. We determined that bulk density response is a reliable indicator of organic content in these thermally immature, water-bearing source rocks. Multimineral findings indicate that a high degree of laminae-scale mineralogical heterogeneity exists due to thinly interbedded carbonate cements amid clay-rich mudstone layers. The lower part of the Eagle Ford Group contains the highest average TOC content (4.7 wt%) and the highest average carbonate volume (64.1 vol%), making it the optimal target in thermally mature areas for source-rock potential and hydraulic-fracture placement. In contrast, the uppermost portion of the Eagle Ford Group contains the highest average volume of clay minerals (42.6 vol%), which increases the potential for wellbore stability issues. Petrophysical characterization reveals that porosity is approximately 30% in this relatively uncompacted formation. In this thermally immature source rock, water saturation is nearly 100% and no free hydrocarbons were observed on the resistivity logs. No evidence of borehole ellipticity was observed on the three-arm caliper log, and horizontal stresses are presumed to be directionally uniform in the vicinity of this near-surface wellbore. This shallow wellbore has a temperature gradient of 1.87°F/100 ft (16.3°C/km) and is likely influenced by earth surface heating.

Organic Petrographic and Geochemical Evaluation of the Black Shale of the Duwi Formation, El Sebaiya, Nile Valley, Egypt

This study evaluates the palynologic, organic, inorganic, and petrographic properties of organic-rich black shale (Mahamid Mine) in the El Sebaiya area, Nile Valley, Egypt. Black shale is composed of quartz (50%), calcite (10%), kaolinite (25%) and montmorillonite (15%). Organic and inorganic analyses revealed that this shale was deposited under oxic to anoxic marine conditions during strong chemical weathering. Black shale has poor to very good organic richness, and poor to fair hydrocarbon potential. Organic petrography indicates that the kerogen is mixed types II/III and III and is immature to marginally mature (%VRo is 0.44 and 0.53). Liptinite macerals consist of alginite, cutinite, and bituminite. The hydrocarbon products to be generated at higher maturity are expected to be oil and gas.