Evaluation Of Hydrocarbon Potential Research Articles

Depositional conditions, wildfires, maturity, and hydrocarbon potential evaluation of Central Carpathian Paleogene Basin based on integrative approach from Orava Basin

Central Carpathian Paleogene Basin (CCPB, Central Western Carpathians) comprises mainly Oligocene clastic autochthonous age-equivalents of the widely known Menilite shale formation from the Outer Carpathians. However, little is known about the paleoenvironment and its subsequent changes during the basin's evolution. Furthermore, the available hydrocarbon potential data are based on anachronous methods and are not investigated on the sub-basin level. Gas chromatography-mass spectrometry (GC–MS) analyses supported by Rock-Eval data along with petrographic measurements enabled us to identify and document the paleoenvironmental evolution of the Orava sub-basin (NW remnant of CCPB). Thermal maturity based on vitrinite reflectance, 22S/(22S + 22R) homohopane ratio and 20S/(20S + 20R) sterane ratio increases from N to S and from Upper to Lower Oligocene. In the least mature samples ββ-hopanes, hopenes, and oleanenes are present, whereas in the most mature deposits less thermally stable compounds dissapeared. This maturation trend is shown also by the Rock-Eval data. Terrestrial organic matter input is documented by the predominance of III- and II/III-type of kerogen and the occurrence of several biomarkers, such as 3,3,7-trimethyl-1,2,3,4-tetrahydrochrysene, cadalene, retene, and perylene. The significant contribution of polycyclic aromatic hydrocarbons (PAHs) may be linked with wildfire-related land degradation and following runoff to the basin. Based on the measured fusinite reflectance values the wildfire types could range from hotter crown fires to colder surface fires. Depositional conditions in Lower Oligocene units are characterized by intermittent euxinia, as derived from small (<5 μm) pyrite framboid diameters and the presence of isorenieratane. Subsequently, a change of conditions to oxic/dysoxic in younger units is observed, and the input of terrestrial organic matter increased.

Evaluating Hydrocarbon Prospects and Petrophysical Properties in Sepinggan Formation, East Kalimantan's Lower Kutai Basin

This study aims to determine hydrocarbon zones and analyze petrophysics in the Sepinggan Formation, located in the lower Kutai Basin, which is one of the oil and gas producing formations in Indonesia. The data used includes 5 well log data and mudlog data. The results of the study show that the Sepinggan Formation has 14 potential zones dominated by carbonate sandstone lithology with a slight mixture of coal. Some key findings in the petrophysical analysis include the largest average shale volume of about 41% in zone 1 of well SPG-V8, the largest average porosity of about 24% in zones 1 and 2 of well SPG-V1, the largest average permeability of about 2591.08 mD in zone 1 of well SPG-V2, and the largest average water saturation of about 56% in zone 2 of well SPG-V7. Based on these results, further evaluation of hydrocarbon potential in the identified potential zones and optimization of exploration and exploitation techniques are needed to improve the efficiency of oil and gas production in the Sepinggan Formation.

Magmatic thermal influence on the metallic element composition of Xiamaling Formation shale: Implications for oil–source correlation and hydrocarbon potential evaluation

The majority of current studies on the influence of magmatic intrusions on shale have focused on how these intrusions affect organic geochemistry and shale reservoir properties. In comparison, less attention has been paid to the changes in elemental compositions generated by the thermal effects of magmatic intrusions into shale, which has limited our understanding of oil tracking and the evaluation of hydrocarbon potential. Here we conduct a case study of magma-associated shale reservoir in the Mesoproterozoic North China Craton using a combination of mineralogy, organic petrology, and geochemistry. The results show that the intrusion-related heating effect resulted in a more acidic and oxidizing diagenetic environment in the shale and that the total organic carbon, vanadium, and rare earth element contents decreased approaching the intrusion. However, the contents of elements (e.g., silicon and barium) associated with organic matter productivity do not exhibit trends pertaining to the distance from intrusion, given their independence from crude oil migration. These findings shed new light on the migration of metal elements during the thermal evolution of shale and can provide a scientific basis for applying metal elements to oil–source correlation and hydrocarbon potential evaluation.

Hydrocarbon detection and depositional environment prognosis in the Niger Delta - Integrated insights from log and seismic avo-inversion attributes

This study demonstrates the effectiveness of integrated seismic analysis and petrophysically constrained AVOinversion for reservoir evaluation and assessment of hydrocarbon potential and depositional environment in the Niger Delta. It is aimed at improved prediction of reservoir fluid, lithology, and ultimately the hydrocarbon prospects, with reduced uncertainties. The results delineate the characteristics of the reservoir sands, highlight major facies heterogeneities, unravel prolific stratigraphic features (such as channels, fan lobes), depositional fairways and provide insight into the mapped geology. These are expected to consequently reduce the uncertainties associated with the prospects for economic decision making.

A Data-Driven Approach to the Unified Evaluation of Conventional and Unconventional Hydrocarbon Resources: Application to Low-Mature to Mature Source Rocks in the Liaohe Western Depression

Hydrocarbon potential evaluation is a high priority in oil/gas exploration which is significantly influenced by evaluation methods and subjective cognition. With the aim of quantitatively establishing a hydrocarbon generation and expulsion (HGE) model of source rocks, a data-driven approach is proposed based on abundant and readily available Rock-Eval/total organic carbon content (TOC)/vitrinite reflectance (VRo) datasets. This approach takes into account the original hydrocarbon generation potential (GPIo) and the loss of TOC. Hydrocarbon generation simulation was also adopted in this study. This data-driven method was applied to the Lower Paleogene Shahejie Formation (Es4), which has three sets of superior source rocks (average thickness &gt; 250 m, TOC &gt; 3%). The GPIo of the Es4 low-maturity source rock was 600 mg HC/g TOC. The initial maturity values of hydrocarbon generation and expulsion were 0.36% and 0.46%, respectively. The Gaosheng sub-member of the Es4 source rock had the largest amount of hydrocarbon generation but a limited amount of hydrocarbon expulsion, implying a favorable exploration of shale oil resources. By contrast, the values of the conventional, unconventional tight, and shale oil resource potentials of the Niuxintuo sub-member were 3.20 × 107, 7.70 × 107, and 5.93 × 108 t, respectively, indicating good prospects for tight oil and shale oil exploration. A comparison between the previous method and the data-driven method showed considerable differences in the restoration of GPIo and TOC, and both had their own limitations. This data-driven approach provides a quick and valid source rock evaluation method and can greatly enhance the accuracy of resource assessment.

Assessment of the Spectral Decomposition Techniques in the Evaluation of Hydrocarbon Potential of “BOMS” Field, Coastal Swamp Niger Delta, Nigeria

Assessment of the Spectral Decomposition Techniques in the Evaluation of Hydrocarbon Potential of “BOMS” Field, Coastal Swamp Niger Delta, Nigeria

Reservoir characterization using integrated seismic attributes and petrophysical parameters in an onshore field of Niger delta basin

An integrated approach of reservoir characterization of a field was performed using seismic attributes and petrophysical parameters for the evaluation of subsurface geological features and hydrocarbon potential of an onshore field in Niger Delta Basin. Four reservoir intervals were identified within the field wells based on their position within the stratigraphic column, and the reservoir correlation, which was aided using the principle of uniform horizontality, based on the simple rule that sediments are deposited horizontally and basic understanding of sequence stratigraphy. The study revealed that, the four reservoirs were predominantly sand units intercalated with shale within the reservoir units. The petrophysical evaluation revealed the Net to Gross (NTG) values ranges from 79% to 87% within the reservoir units, while the effective porosity ranges from 17% to 21%, the permeability ranges between 1307mD to 1678mD across the reservoir units, while the water saturation ranges from the lowest of 35% (Reservoir C) to 78% in reservoir D. A total of fifteen faults were interpreted using the seismic data, while the surface maps (Time and depth surface maps) revealed the identified closures which are anticlinal structures that are fault dependent. The characterization of the reservoir was further enhanced using the seismic attributes (structural and stratigraphic) extracted such as Reflection intensity, Sweetness, Variance, Envelope, Instantaneous frequency, Time gain, Trace AGC, Local structural dip, Gradient magnitude and RMS amplitude. The results shows moderate to high sweetness (sweet spots) within the zone of interest, while the Envelope attribute show acoustic impedance contrasts indicating discontinuities, lithology changes and possible present of hydrocarbon (Bright spots). The variances and gradient magnitude enhanced the signal to map out discontinuities caused by faults and fractures which are signature that enabled delineation of the zone. The integrated approach validates the lithology discrimination of the elastic properties from the well logs and its effectiveness in optimizing and proper understanding of the subsurface, thus identifying and unmasking hidden features within the reservoir (probable bypass) in the field. The study has revealed that the integration of seismic attributes with petrophysical parameters is a better characterization method for fluid and lithology discrimination of a field in any given reservoir study.

Quantitative Interpretation of Petrophysical Parameters for Reservoir Characterization in an Onshore Field of Niger Delta Basin

Reservoir characterization of a field was performed using petrophysical parameters for the evaluation of subsurface geological features and hydrocarbon potential of an onshore field in Niger Delta Basin. Four reservoir intervals were identified within the field wells based on their position within the stratigraphic column, and the reservoir correlation, which was aided using the principle of uniform horizontality, based on the simple rule that sediments are deposited horizontally and basic understanding of sequence stratigraphy. The study revealed that, the four reservoirs were predominantly sand units intercalated with shale within the reservoir units. The petrophysical evaluation revealed the Net to Gross (NTG) values ranges from 79% to 87% within the reservoir units, while the effective porosity ranges from 17% to 21%, the permeability ranges between 1307mD to 1678mD across the reservoir units, while the water saturation ranges from the lowest of 35% (reservoir C) to 78% in reservoir D. The approach validates the lithology discrimination of the elastic properties from the well logs and its effectiveness in optimizing and proper understanding of the subsurface, thus identifying and unmasking hidden features within the reservoir (probable bypass) in the field. The study has revealed that petrophysical parameters can be used quantitatively to characterize a field in terms of its lithology and fluid contents of the reservoir.

A Technique of Hydrocarbon Potential Evaluation in Low Resistivity Gas-Saturated Mudstone Horizons in Miocene Deposits, South Poland

The petrophysical properties of Miocene mudstones and gas bearing-heteroliths were the main scope of the work performed in one of the multihorizon gas fields in the Polish Carpathian Foredeep. Ten boreholes were the subject of petrophysical interpretation. The analyzed interval covered seven gas-bearing Miocene horizons belonging to Sarmatian and Badenian deposits. The water saturation in shaly sand and mudstone intervals was calculated using the Montaron connectivity theory approach and was compared with Simandoux water saturation. Additionally, the Kohonen neural network was used for qualitative interpretation of four PSUs (petrophysically similar units), which represent the deposits of comparable petrophysical parameters. This approach allowed us to identify the sediment group with the highest probability of hydrocarbon saturation. Then, the spatial distribution of PSUs and reservoir parameters was carried out in Petrel. The resolution of the model was selected to reflect the variability of log-derived parameters. The reconstruction of the spatial distribution of shale volume, porosity, and permeability was performed with standard parametric modeling procedures using the Gaussian random function simulation stochastic algorithm, while PSU distribution and hydrocarbon saturation (SH) required a separate approach. The distribution into PSU groups was carried out by facies classification. Predefined ranges of clay volume, effective porosity, and permeability were used as discriminators to achieve spatial distribution of the PSU groups. The spatial distribution of hydrocarbon saturation was performed by creating the meta-attribute of this parameter and then reducing the derived pseudo-saturation model to physical values. Results included the creation of maps of hydrocarbon saturation that show the preferable areas with the highest hydrocarbon saturation for each gas horizon.

Evaluation of hydrocarbon potential of shale outcrops in the flanks of Anambra Basin

The research aim is to determine the organic productivity and hydrocarbon potential of the exposed shale lithology along Uzebba road and Bawa hills near Auchi, Southwest Nigeria.Twenty two (22) shale samples were acquired from the study area; twelve (12) from the outcropping section along Uzebba road, and the remaining ten (10) samples obtained from Bawa hills. The samples were then subjected to organic geochemical analysis using Total Organic Carbon (TOC) and Rock Eval Pyrolysis to evaluate the organic enrichment, organic quality and thermal maturity espectively.Total Organic Carbon (TOC) content of the twenty-two samples ranges from 3.42 – 4.88 wt. %, affirming a high organic enrichment. Shale samples from Uzebba segment and Bawa hills falls within the Type I and Type II Kerogen class respectively. The former is indicative of immature – sub mature organic matter with no hydrocarbon formation prospect whilst the latter exhibits great hydrocarbon (oil) generation potential Thermal maturation assessment for both samples apparently ranges from immature to mature organic matter. From the Rock-Eval pyrolysis result, all the twenty-two (22) samples were confirmed to be organically enriched. However, the type I kerogen of Bawa at favourable geothermal gradient can potentially serve as a suitable source rock for petroleum generation.

An integrated approach to evaluate the unconventional hydrocarbon generation potential of the Lower Goru Formation (Cretaceous) in Southern Lower Indus basin, Pakistan

Southern Lower Indus basin is an oil and gas prone basin, which is important for producing hydrocarbon in Pakistan. Due to limited Rock-Eval pyrolysis data availability in the prospective shale gas basin, the organic facies geochemical characteristics study is a challenging task for researchers. The primary objective of this study is an evaluation of the Lower Goru Formation organic facies hydrocarbon potential by geochemical data and its subsurface facies distribution study by well tops and seismic data. The study area is situated at the Southern Lower Indus basin of Pakistan that is considering the prospective shale gas basin with immense unconventional hydrocarbon potential. In the present study, Rock-Eval pyrolysis data analysis along with the integration of both seismic and well tops data were conducted for investigation of source rock generation potential of organic facies variability within the Lower Goru Formation. The geochemical approaches used in the current study show that the Lower Goru Formation encountered in, bears fair to excellent total organic carbon (TOC) content values of 0.50–3.60% in Well-A and 0.10–4.69% in Well-B. Additionally, the results of Rock-Eval pyrolysis data show that interbedded shales of the Lower Goru Formation contain different types of kerogen (III, II–III, and II) with variable generation potential of oil and gas.

Evaluation of hydrocarbon potential with insight into climate and environment present during deposition of the Sonari lignite, Barmer Basin Rajasthan

Lignite samples from the Sonari mines of Barmer Basin, Rajasthan, India have been studied for the first time by applying advanced petrochemical techniques. The objective of the study was to reconstruct Paleomire conditions and to examine the source rock potential of the lignite-bearing sequence. Based on the mean huminite/vitrinite reflectance values (0.24–0.31%Ro), all of the samples studied are lignite B in rank. Geochemical analysis results show, the atomic ration H/C and O/C ranges from 0.03–0.15 and 0.27–0.61 respectively, hydrogen index (HI) and oxygen index (OI) ranges from 173 to 256 mg HC/g TOC and 29–55 mg CO2/g TOC respectively, with Tmax value (415–416 °C), entails these lignites are thermally immature and contain type III kerogen. The studied lignites have total organic carbon (TOC), and S2 values vary from 41.24–49.19wt% and 78.53–119.81 mg HC/g rock, respectively, which indicate that these lignites may be served as good hydrocarbon source rock.The lignites are principally composed of huminite (mean 47.5 vol%) and inertinite (mean 31.4 vol%) group of macerals with a low concentration (mean 8.5 vol%) of liptinite macerals. The predominance of attrinite in the Sonari lignite samples suggests that woody vegetation has undergone significant degradation. Petrographic indices such as TPI (Tissue preservation index; 0.92–2.13), GI (Gelification index; 0.97–8.25), GWI (Groundwater influence index; 0.34–1.50), and VI (Vegetation index; 0.16–1.84) indicate deposition in a wet forest paleomire and peat formation under ombrotrophic to mesotrophic hydrogeological conditions. Ternary plots based on maceral and microlithotype entails fluctuating water table condition during peat deposition.The GC-MS (Gas chromatography–mass spectrometry) data shows that the ratios, Pr/Ph pristine/phytane (˂1), Pr/C17 (0.57), Ph/C18 (0.25) and carbon preference index (CPI) value 3.73 along with δ13C (−25.04%) values indicate that the Sonari lignites are composed primarily of gymnosperms taxa which formed under relatively dry and cold paleoclimatic conditions. Besides, FT-IR (Fourier-transform infrared spectroscopy) spectra give the signature of a C–H aliphatic stretching region and predominate methylene group in the aliphatic carbon region, which is also observed in the NMR (Nuclear magnetic resonance).

Thermal structure and source rock maturity of the North Peruvian forearc system: Insights from a subduction-sedimentation integrated petroleum system modeling

Basin modeling is commonly used for the hydrocarbon potential evaluation of underexplored areas, taking into account the full basin history to assess its thermicity and fluid distributions. In the case of forearc basins, however, the influence of the subduction on the internal thermal structure is difficult to predict. The existing subduction thermal models usually focus on the present day lithosphere and do not consider the sediment infill history, while industrial modeling tools handle the thermal evolution of sedimentary basins but not the subduction process. In this paper, we propose a solution model in which the cooling engendered by the subduction is represented by the advective term of the heat conservation energy equation throughout the sedimentation. This study focuses on the Talara-Tumbes-Lancones petroleum province, part of the North Peruvian forearc system. Despite the long term exploration of the Talara Basin, the origin of its massive oil fields still remains questioned. The new subduction-sedimentation integrated petroleum system modeling presented here, calibrated by numerous structural and thermometric data, allows to better constrain the thermal structure and source rock maturity history of this forearc system. We show that the exposure of the sedimentary basin to the subducting cold lithosphere, the sedimentation rate and erosion are important factors impacting the maturity of the source rocks. Consequently, even in the same subduction setting, each depocenter of the North Peruvian forearc system presents a different thermal history and maturity timing, and each basin presents an independent petroleum system.

Evaluation of shale hydrocarbon potential in upper Talang Akar formation based on laboratory geochemical data analysis and Total Organic Carbon (TOC) modelling

In shale hydrocarbon exploration, shale acts as the source rock and reservoir rock. This study aims to evaluate the potentional of shale hydrocarbons based on the laboratory geochemical data and TOC (Total Organic Carbon) modelling. Evaluation of shale hydrocarbons in sthe study field was carried out on two wells, X-1 and X-3 wells with a target in the upper part of Talang Akar formation as a source rock. Geochemical data is needed for evaluating the quality of the source rock by looking at the total organic carbon content, the maturity, and the hydrocarbon produced by the source rock. Analysis of the laboratory geochemical data resulted that the shale of upper Talang Akar formation had enough potential and mature organic material and also will generate the hydrocarbon in oil form. One of the main parameters for the success of shale hydrocarbons exploration is to know the amount of organic material of the source rock. TOC obtained from laboratory geochemical data is discrete data. Therefore, TOC modelling is carried out to obtain prediction of continuous TOC in upper Talang Akar formation in both wells. This prediction uses three different methods, those are Passey, multiple linear regression, and neural network. Based on those three methods, neural network produces the best data. The correlation obtained from X-1 well and X-3 well using neural network method are 0.96 and 0.84 respectively.

Analysis of high-resolution aeromagnetic (HRAM) data of Lower Benue Trough, Southeastern Nigeria, for hydrocarbon potential evaluation

ABSTRACT The analyses of high-resolution aeromagnetic (HRAM) data of lower Benue Trough in southeastern Nigeria have delineated sections of the basin with requisite sedimentary thickness that could support the generation of oil and gas from right-type organic-matter rich source rock as well as identified intra-sedimentary structural framework that could aid hydrocarbon migration and restrain generated hydrocarbon within available reservoirs. The susceptibility and Analytic Signal (AS) maps derived from processed Gaussian-filtered and Reduced to Pole at Low Latitude (RTPLL) aeromagnetic data discriminate crystalline basement rocks from the sedimentary units. Likewise, many relatively shallow, short (900–1600 m) intra-geologic terrain linear structures and fewer long, deeper (>1.5–43 km) inter-geologic terrains crustal linear structures which reduce in population but increase in lateral extent and depth with increasing continuation distances were delineated from the processed Tilt Derivative (TDR) and the Horizontal components of the Tilt Derivatives grids at different Upward Continuation distances. Euler Deconvolution depth-weighting analyses determined depth to magnetic sources which ranges in value from 120 m above to 5 km below the Minna reference datum. Regions having sedimentary thickness in excess of 3 km with active intra-sedimentary structural elements qualify for further petroleum exploration campaign using other detailed geological and geophysical tools.

Evaluation of hydrocarbon potential using fuzzy AHP-based grey relational analysis: a case study in the Laoshan Uplift, South Yellow Sea, China

Abstract Effective evaluations of hydrocarbon potential contribute to delineating promising target areas for further exploration. Sparse available data and known hydrocarbon reservoirs in frontier areas present considerable challenges to the weighting of geological factors when evaluating hydrocarbon potential. This study proposes a hydrocarbon potential mapping method that employs grey relational analysis (GRA) based on a fuzzy analytic hierarchy process (fuzzy AHP). GRA is a comprehensive evaluation method that represents the hydrocarbon favourability according to the proximity between evaluation targets and the ideal target based on multiple evaluation factors and weights among them. To overcome the uncertainty and vagueness in the weighting procedure, the fuzzy AHP technique relies on experts’ knowledge to define the relative importance of evaluation factors and exploits triangular fuzzy numbers to simulate experts’ judgements in pairwise comparisons. The fuzzy AHP-based GRA method was tested using an example in the Laoshan Uplift in the South Yellow Basin of China. This test application not only quantified the favourability of local traps but also revealed their spatial variations on favourability maps and indicated potential targets for further exploration. The results obtained by the fuzzy AHP-based GRA method were more reliable than that of entropy weight-based GRA and displayed a suitable consistency with known geological information, thus demonstrating that such a procedure could reveal the potential spatial features of hydrocarbon accumulations and support the evaluation of hydrocarbon potential in relatively unknown areas.

Evaluation of hydrocarbon potential, quality of source rock facies, and delineating of their depositional environment in Mamu Formation of Anambra Basin, Nigeria

This investigation was carried out by collecting a total of six shale samples from two exposures of Mamu formation in Enugu and Igarra for geochemical analysis for investigation of source rock potential and environment of deposition. The values of TOC (1.79-3.16wt %) and SOM (1450 – 1625ppm) reveals that the shale of Mamu at the two locations are good – very good source rocks. The plot of hydrogen index against oxygen index and TOC against petroleum genetic potential shows both type III and IV kerogen indicating a gas prone and inert kerogen content. The values of Tmax ranges from (390 O c – 437 O C) suggesting that the source rock is immature to early thermally mature. Finally, the cross plot of TSC against TOC confirms a normal marine depositional environment for the samples collected at both locations. Keywords: Hydrocarbon Potential, Environment of Deposition, Mamu Formation, Cross Plot

Hydrocarbon potential of Upper Bahariya member in Um Baraka oil field, North Western Desert, Egypt

ABSTRACTThe present study deals with the hydrocarbon potential evaluation of the Upper Bahariya Member (Upper Cretaceous) in Um Baraka field, North Western Desert. The Upper Bahariya Member is characterised by sandy shale facies in the UMB-152 well, calcareous shale facies in the UMB-89 well and calcareous sand facies in the UMB-108 and UMB-130 wells, these facies reflect to fluvio-marine environment changing to shallow marine environment. The petrophysical parameters results of Upper Bahariya Member are represented laterally (Iso-parametric maps, such as effective porosity, shale content, net-pay thickness and hydrocarbon saturation variation maps) and vertically (Litho-saturation cross-plots). The Iso-parametric maps revealed that the promising hydrocarbon-bearing zones are characterised by their clay content range from 1.7% to 21.4%, effective porosity ranges from 13.2% to 19.7%, net pay thickness range from 7.5 ft to 15.5 ft, and hydrocarbon saturations range from 39.3% to 68.3%. The log analysis and petrophysical parameters results indicate that the Upper Bahariya Member is considered to be the main potential reservoir in Um Baraka field. The petrophysical parameters of the Upper Bahariya reservoir illustrated the improvement of the reservoir properties of Upper Bahariya Member towards the north and northwest and northeast directions, due to increasing of total porosity, effective porosity and hydrocarbon saturation.

Sedimentogenic Aspect of Evolution and Hydrocarbon Potential of the Aldan-Maya Sedimentary Basin (Southeast of the North-Asian Craton)

The main features of the lithofacial conditions of formation of the sedimentary complex of the Aldan–Maya Sedimentation Basin (AMSB) are discussed. It is shown that different facies (continental, coastal–marine, and marine) were formed under the conditions of one sedimentation basin of the type of one-side syneclise, which was formed on the eastern slope of the Aldan anteclise of the North Asian Craton, at its contact with the Okhotsk Massif. We distinguish and characterize the main sedimentation stages separated by inversions, magmatic layers, and weathering crusts (from the bottom upward): Pre-Riphean (Late Karelian, Ulkanian); Early Riphean (Uyan–Uchur); Middle–Late Riphean (Kerpyl–Lakhanda–Uisk); and Vendian–Cambrian. Areas of bituminous lithocomplexes are revealed in the sedimentary cover of the AMSB. Structural and sedimentary events in the AMSB are related to the geodynamics of the southeastern zone of the North Asian Craton and to the hydrodynamic regime of the Okhotsk–Pacific sector of the World Ocean. The article is devoted to the problems of comprehensive study of the geology, deep structure, and geodynamics and evaluation of hydrocarbon potential of the AMSB.

Identification of Hydrocarbon Potential of Talhar Shale: Member of Lower Goru Formation Using Well Logs Derived Parameters, Southern Lower Indus Basin, Pakistan

Evaluation of shale gas hydrocarbon potential of Talhar Shale member of Lower Goru Formation, by using well logs data only, has been a challenging task in Southern Lower Indus Basin Pakistan. This paper is helpful to evaluate shale gas potential of source rock by using well log data. We have introduced and applied Empirical and Graphical method to resolve this task and have derived geochemical parameters from well logs data. The way mentioned is fastand the cheapest. Talhar Shale has kerogen typeIII and type II which has potential to produce, mainly, oil and gas. Talhar Shale is of Montmorillonite clay type. So, Talhar Shale has better sorption property. Empirical formulas are used to derive parameters, using well logs of Porosity, Density and Uranium. Porosity and Volume of Kerogen, calculated from density log, gives average values of 11.8% and 11.4%. Level of Maturity Index (LMI), derived by log, average value is 0.54 which indicates that it is on early stage of maturity. Vitrinite reflectance is between 0.5-0.55% as calculated by graphical method and empirical formula. Talhar Shale with main products of oil and gasis onset of oil generation,;could be a good potential source in the study area.