Selected Studies in Geophysics, Tectonics and Petroleum Geosciences

In this paper, the hyperbolic secant time-scale transform and their application to seismic volcanic signals are presented. Results on identification/classification of the volcanic event show a promising tool for volcanic seismic signal processing and analyzing.

Ionospheric disturbances are associated with the propagation of seismic waves generated by earthquakes. We analyze total electron content (TEC) fluctuations from Global Navigation Satellite Systems (GNSS) data. This study investigates the global earthquakes from December 2004 to March 2020 with magnitude (Mw) 4.0 to 9.1. Data of 65 permanent GNSS stations are used to analyze the impacts of these earthquakes on the ionosphere. The experimental data based on the cluster sampling method ensure strict conditions such as accuracy, the distance from the monitoring stations to the epicenter, and the depth of the hypocenter. At least three GNSS stations near the epicenter participate in the analysis of each earthquake. Probability and statistics are applied to remove outliers and rough errors in the input data, to select datasets with similar quality, and to analyze TEC anomalies. The results show that when a strong earthquake occurs, the TEC values calculated at different GNSS stations surrounding the earthquake region tend to exhibit similar variations. Depending on the magnitude, epicenter, and hypocenter depth, these fluctuations can range from ± 3.2 TECU to ± 14.5 TECU for large earthquakes. These TEC fluctuations occur from 30 min to almost two hours before the mainshock of the earthquakes and last to the aftershock period. For earthquakes with a magnitude greater than 6.0 Mw, the TEC fluctuations are significant. The findings of this study contribute to GNSS applications in studying earthquakes in the future.

Several strong earthquakes have occurred in the Al-Hoceima region of northern Morocco in the last few years, including the magnitude Mw 6.0 May 1994 earthquake, magnitude Mw 6.0 February 2004, and magnitude Mw 6.4. January 2016 earthquakes. Therefore, the infrastructure (e.g., faculty, municipal stadium) in this region requires a suitable earthquake-resistant design, especially in areas that include well-established neotectonic activity. The aim of this study is to find the areas that show the most significant surface tectonic activity in Al-Hoceima during the period 1990 and 2019. A Geographic Information Systems (GIS) spatial data analysis was performed based on the seismic catalog published by the National Geographic Institute (IGN) and Landsat data. The results of this study show that the western region of Al-Hoceima has the highest tectonic activity in the region as expressed by its structures of high lineament densities and the occurrence of several strong shallow earthquakes. The study of hypocentral earthquakes allows us to identify the presence of active faults, especially when the earthquake foci form a linear pattern.

Land subsidence affects the vertical control component of the height system in Louisiana at a state-wide level. The National Height Modernization System (NSRS) has been initiated by the National Geodetic Survey (NGS) to enhance the vertical component of the NSRS in the USA. In addition to the positional coordinates, NSRS combines scale, gravity, orientation, and their variation with time. In this study, we estimate and analyze the land subsidence in Louisiana using GNSS data since 2013. We selected 15 well-distributed Continuously Operating Reference Stations over the Louisiana State from the GULFNet network, which is managed by the Center for Geoinformatics at Louisiana State University. The daily GNSS files collected from the GULFNET are processed using an automated procedure to overcome and organize the multi-step tasks. These tasks include the preprocessing (to perform quality control), processing with GipsyX software to obtain the daily solutions, and post-processing to estimate the velocities and the associated uncertainty. In the preprocessing task, various applications are employed to organize and process the raw data files and convert them into RINEX. Final orbits and clocks are also downloaded from JPL in order to obtain the daily solutions with respect to ITRF2014 using GipsyX. Finally, the horizontal and vertical velocities are estimated in time series for all stations and analyzed using the Hector software. The analyzed stations show land subsidence; the highest land subsidence rate (−6.15 mm/yr) is detected in the LMCN station on Louisiana south coast.

This study discusses the analysis of two earthquakes that occurred on the border between Slovenia and Croatia on March 22, 2020, of magnitude 5.3 and 4.9, respectively. The epicenters were not far from each other and with the hypocenter located 10 km away. The microgravitational variations with the graph of a seismograph supplied in the same monitoring station, located in Rovigo in northeastern Italy, before, during, and after the earthquakes were compared. The comparison of the graphs shows that the first earthquake was preceded by a microgravitation variation of about 5 milliGal before the main shock of magnitude Mw 5.3 by about 32’. However, the local microgravity change was not recorded by the seismograph, nor was the damped gravitational wave that followed. We can deduce that it was a variation of the local gravity, not influenced by the passage of the seismic waves which preceded the earthquake. The amplitude of the damped waves is also compatible with the energies of the two earthquakes and is comparable with the Magnitude Scale.

The gravity measurements in Sudan are sparse and few compared to the country area. The currently available measurements were conducted for the sake of mining and oil exploration between the 1970s and mid of 1980s. However, in precise geodetic works such as geoid determination, the gravity data must be dense and have good quality to obtain reliable solutions. This study uses global geopotential models (GGMs) and altimetry to fill gaps in gravity measurements over land and the Red Sea, respectively. We validate the GGM-based free-air gravity anomalies (FAA) with the terrestrial ones to select the best-fit model for inland filling. We use three GGMs (EGM2008, XGM2019e, and EIGEN6C4) truncated at 760 degrees/order in the validation to select the best-fit model. The selection of the best-fit model is based on the consistency between GGM and terrestrial anomalies and the minimization of their standard error (SE). In addition, the topographic effect has been considered; therefore, the topographic effect (TE) is calculated and applied. The altimetry data were employed in filling the Red Sea marine area adjacent to Sudan. To reduce the error propagation, the validated points were refined by setting the differences between the terrestrial, GGM data, and TC to a certain range according to the quality of the validation data. The final combination of the terrestrial, GGM, and altimetry data is introduced as a newly improved gravity grid of Sudan; statistical and numerical results are also presented.

The Paleocene and Middle Eocene in the Senegalo-Mauritanian sedimentary basin contain significant phosphate resources. The exploration and evaluation of these strategic resources are hindered by uncertainties about the geometry of the layers. The main sources of uncertainty are tectonic movements and post-depositional sedimentation phenomena. Given the high cost of drilling and the need for sufficient precision, remote sensing data have been integrated into the combination of geophysical methods (electrical tomography and seismic refraction) and core drilling to reduce the main geological uncertainty. This combination allowed the “overburden–ore” and “ore–wall” interfaces to be more accurately defined. Application of the method allowed optimizing the planning and the number of drill holes and consequently reduced the exploration costs significantly.

The salinization of groundwater is one of the main causes of the degradation of water quality. The water quality of the arid to semiarid regions of Tunisia depends on the captured formations and the nature of the water resources of the aquifers (renewable or ancient). In general, salinity could exceed 4 g/l. These high salinities are mainly due to the dissolution of evaporates and the lithological nature of the aquifers. However, salinities below 2 g/l (1 to 1.5 g/l) are encountered in feeding areas in carbonate and sandy structures that are protected from sources of contamination. In this paper, electrical resistivity surveying involving vertical electrical sounding and 2D profiling has been carried out to determine the distribution of salinity in the Plio-quaternary aquifer near Tfal wadi. This study allowed us to identify the origin of the salinization of the Plio-quaternary water table in the study area and to determine the extent of this salinization. The geophysical surveys, through geoelectric cross-sections and tomographic profiles, have made it possible to determine the extent of salinization, while showing the presence of Sebkha, which is the main origin of the salinization.

A combination of post-stack seismic attributes including Similarity, Curvature, and Chaotic Reflection has been used to show their effectiveness in delineating the subsurface geological features that were hardly comprehensible using conventional 3D seismic amplitude volumes. This study shows how the subtle patch-reefs and the complex meandering channel system, which were not initially well-defined in conventional seismic volumes, appear on different attribute slices. Multiple attribute signatures have been presented to confirm the channel signature, and differences have been discussed in detail. Attribute volumes have been generated using time-migrated seismic volumes from two different basins of the world: Indus Basin, Pakistan, and Taranaki Basin, New Zealand. Expression of patch-reefs and channel systems from the data sets used are very helpful in understanding the geometry and depositional environments of the mentioned features and could lead to the identification of potential hydrocarbon traps in different areas. An optimum parameter selection, especially for differences in the subsurface geology, is discussed in detail.

Ngimbang Clastics within the JS Ridge, North East Java Basin is proven to be a productive hydrocarbon interval. The area is surrounded by three possible kitchens (deeps) which are the Central Deep, Tuban Trough, and Lamongan Deep. Apart from the traditional carbonate system of the Kujung Formation as the main reservoir, the occurrence of the older interval of Ngimbang Clastics is also considered as the deeper reservoir target. This interval is characterized by thin-bedded sandstone, conglomeratic sandstone, and shale deposited as syn-rift products on the fluvial-estuarine environments. Rock physics analysis has been carried out by connecting well logs and seismic inversion results in order to discriminate the reservoir from other lithology and to know the fluid content within this reservoir. This process is conducted to find an appropriate model with a reasonable match between the elastic parameter and well data. Fluid content and contact that are accurately estimated by the Vp/Vs ratio can be transformed to seismic data by the Poisson Impedance (PI) inversion method. PI is calculated by subtracting Acoustic Impedance with Shear Impedance ( $${\text{PI}} = {\text{AI}} - c{\text{SI}}$$ PI = AI - c SI ), where $$c$$ c is a term of rotation value of the AI-SI data. The Poisson Impedance (PI) inversion is a type of pre-stack inversion, where this technique enhances the appearance of distribution and fluid content within siliciclastics reservoir rocks of Ngimbang Clastics sandstone interval. In this interval, a low value of Poisson Impedance indicates gas sand with a range of 500–6500 ft/s*g/cc. The low value of Poisson Impedance and Vp/Vs ratio identifies gas content in a reservoir. Therefore, it is applicable to discriminate between sandstone reservoirs and non-reservoirs.

Seismic inversion is a method of processing seismic data to predict different properties of rocks such as density, compressibility, velocity, water saturation, porosity, permeability, and layer thickness. This is how it seems important to us to use seismic inversion to characterize the nature of reservoir rocks. This work uses the different types of seismic inversion that are related to AVO analysis to perform lithological analysis of hydrocarbon reservoirs using 3D seismic data from Penobscot located in offshore Nova Scotia (Canada). These are elastic inversion, acoustic inversion, and inversion by attributes which constitute the methods used. The results allow good discrimination of different layers of hydrocarbon reservoirs using a combination of attributes. Thus, the cross-plotting of the density and the Poisson ratio made it possible to highlight four facies.

Multivariate geochemical data possess many challenges for statistical modeling, such as the multivariate dependencies between the chemicals on-site and the spatial dependencies that need to be considered. Recently, spatial blind source separation (SBSS) was suggested, where it is assumed that the multivariate measurements are formed as linear combinations of unobserved random fields that are uncorrelated and fulfill second-order stationarity assumptions. In this work, we refine SBSS by suggesting a new local covariance matrix which is based on local differences. This leads to a more robust SBSS approach which can tolerate violations of the second-order stationarity assumption. We illustrate our approach by analyzing a geochemical dataset derived from the GEMAS project.

The In Ouzzal Granulitic Unit (IOGU) is an Archean/Paleoproterozoic terrane located in the Northwestern part of the Tuareg Shield, in southern Algeria. The IOGU lithosphere was first remobilized during the Paleoproterozoic and then by the Pan-African orogenies. Magnetotelluric (MT) survey consisting of 12 sites was carried out in the In Ouzzal terrane along the East–West profile with approximately a hundred kilometers long. The main objective of this study is to evaluate the electrical anisotropy of the In Ouzzal underlying lithosphere. For dimensionality and directionality analysis, we used the phase tensor method and the real induction arrows. The outcomes show that data for periods up to 1 s are more consistent with 3D with a strike angle of N20°E. The direction of the real induction arrows according to the Parkinson convention is in agreement with the regional geological strike of the IOGU. It is well known that electrical anisotropy can have a significant influence on the MT responses and may create artifacts in isotropic inversions. The combination between the phase split and the induction arrows’ patterns reveals two electrical anisotropy zones at the lithospheric mantle level, where each of them is located in the western and the eastern parts of the profile.

The quantitative petroleum reservoir analyses’ topic is one of the biggest challenges facing geo-modelers. The difficulty lies in the fact that the constructed model depends on many empirical Archie’s law parameters such as tortuosity factor (a), cementation exponent (m), and saturation exponent (n). The most used methodology of choosing the appropriate set values of (a, m, n) is the trial/error technique. The parameters values’ sets are calculated empirically based on core data taken from different wells. The main drawback of this method is that these petrophysical parameters are not constant all over the reservoir section and are very variant in non-conventional reservoirs. The objective of this study is to provide curves of the petrophysical parameters (a, m, n) from petrophysical logs based on new equations. The new equations are based on relating tortuosity as a function of the sonic log and other basic logging curves (Gamma Ray, Neutron-density). Then, the calculated curves are used in constructing a more accurate non-conventional reservoir model. The obtained results have been compared to the conventional interpretation where a, m, and n are taken constants for all reservoir sections. Moreover, the obtained results are validated through core data and MDT tests in Algerian Southern non-conventional reservoirs.

One of the biggest challenges facing Geoscientists and reservoir modelers is how to improve the descriptive understanding of the hydrocarbons reservoir, and therefore, define the best representative reservoir properties (e.g., fluid flow capacity) in the simulation model, whereas poorly described reservoir characteristics can lead to a significant impact on reservoir performance predictions and its future production behaviors. In order to master the Quartzite El Hamra reservoir in Southern part of Hassi Messaoud field in Algeria, this study was dedicated to characterize the petrophysical properties by using rock typing and flow unit techniques (Winland R35 and FZI). The main objective was to evaluate the pore level’s influences on reservoir quality and log response and to study the relationships between the composition of pore geometry and reservoir quality. This allowed us to understand the factors that control the quality of the reservoir and the fluids’ flow characteristics. Moreover, this study was based on detailed description and laboratory tests on cores and thin sections and the integration of this information with geological, Petrophysical, and engineering data. Furthermore, appropriate set of reservoir properties (i.e., porosity—permeability ratio, R35, storage percentage, and percent flow) are well defined for six identified Hydraulic Flow Units (HFUs). The obtained results can improve reservoir simulation studies for performance prediction, history matching, and future development decisions in the field.

The main objective of this study is to characterize the potential reservoirs situated in Oued Mya basin in Algeria by using pre-stack seismic inversion data. In fact, rock physics has been used to estimate shear waves and their densities from the compressional wave velocities at six wells, and then, cross-plots were exploited to establish a mathematical relation between the petrophysical and acoustic parameters of the rocks. After that, the lithological classification has been iteratively generalized for the whole seismic volume. The final model, obtained with a correlation ratio of 75%, allowed the classification of the dominant facies in the reservoir. Furthermore, the Petrophysical volumes obtained using these mathematical relations provided the horizontal distribution of the different existing reservoirs with a focus on the potential ones. The obtained results in this case study have highlighted the crucial role played by the seismic inversion in the characterization of the oil reservoirs in the Oued Mya Basin. It also permitted to provide lateral variations of petrophysical parameters of the reservoir; thus, it eliminates the problem of punctuality of the information provided by logging data. This characterization step is very important for determining the positions of new exploration drillings in order to optimize exploration strategy with minimal uncertainties; therefore, exploration costs can be optimized. The main novelty of this paper is that the obtained model was very reliable and its correlations with six wells in the basin were high; hence, it has been used to characterize the reservoirs and to identify new areas with hydrocarbons potentials where highly probable discoveries were identified.

In this paper, a new workflow of geometrical seismic attributes for a structural geological study has been proposed. The small faults with low throw were detected, and the natural fractures’ model has been obtained for tight reservoirs. The fractures model has been correlated with imagery data taken from exploration wells in the studied field. The proposed attributes allowed us to map major faults with a throw less than the seismic resolution, and the curvatures have also been used to map subtler folds and flexures and overlying other formations. The geometrical seismic attributes used are: Curvature, Variance, Chaos, Structural smoothing, Edge enhancement, and Ant tracking. Moreover, the effectiveness of the proposed methodology has been demonstrated through the case study of Ain Amenas tight reservoir. The obtained results have been compared to conventional seismic interpretation results, for which it was demonstrated the existence of small faults that cannot be seen by the old methodology. Therefore, the constructed fracture model has been correlated and matched to the results of imagery interpretation of data taken from wells in the field. Finally, a relationship between fracture density and the attributes has been proposed in order to be considered for reservoir model construction in the production phase. This workflow can be useful in the optimization strategy of exploration costs of hydrocarbon resources of oil and gas national companies. The main novelty of this study is that it provides a practical workflow tool for continuous fracture modeling (CFM) and its successful application to several projects.

The Bir Haddada Plain is located in eastern Algeria and is characterized by a semi-arid climate with low rainfall. The irrigation of this region's agricultural lands is almost assured by hundreds of wells that exploit the shallow aquifer. The strong pumping of the shallow aquifer triggered the latter's utter exhaustion. To resolve the irrigation water shortage, we need to explore the subsoils to find potentially exploitable aquifers more closely. The objective is the geoelectric characterization of this area and also the detection of underground water aquifers. The geophysical study by vertical electrical survey (VES) is more adequate because it allows identifying the conductive and resistant layers to the electric field. Exploration by VES was carried out with a spacing of the measuring electrodes ranging from AB = 100 to AB = 1000 m. The study of the results obtained indicates that the prospective zone is distinguished by a filling exceeding 300 m corresponding to the miopliocene formations. These formations are generally clays, conglomerates, and lacustrine limestones. In contrast, the low resistivity values seem to be related to the presence of conductive formations such as Miopliocene gypsum clays or to the presence of Triassic rocks linked to the contact of the bedrock. The maps of the apparent resistivity often show a network of different direction faults.

During recent years, Digital Rock Physics gained wide attention in the industry as a tool to integrate petro-physical measurements on core plugs, from routine to special core analyses. The acquisition of a sample from a producing siliciclastic gas field was performed at the Elettra synchrotron facility to obtain a significant volume in a short time. Different image processing pipelines were tested and the impact of the chosen workflow was analyzed in terms of porosity, absolute permeability, and fluid velocities’ distributions. The entire acquired volume was processed to obtain a porosity–permeability trend. SEM images were integrated to better characterize sub-resolution phases. The results were then compared to the routine core analyses (RCAs) performed on the same samples by two different laboratories and integrated with an acquisition performed at ENI X-ray imaging laboratories.

Wettability has been known to be responsible for multiphase flow in porous materials and is conventionally characterized as the three-phase contact angle to describe its complex interactions of two immiscible fluids and a solid medium. Even though a simple ex-situ measurement of the contact angle on a surface is widely conducted, an in-situ contact angle that cannot be physically measured has increasingly been accepted as a more crucial and meaningful parameter for oil displacement. Since the in-situ contact angle considers a holistic and yet dynamic movement of fluids within porous material, a number of indirect in-situ characterizations have been performed. The current work aimed to examine a new alternative via an analytic method to characterize in-situ wettability. In this study, a correlation on spontaneous imbibition developed by Standnes was used to characterize in-situ contact angle with Lambert’s $$W$$ W function. The in-situ contact angles of 160 experiments on oil displacement in sand-pack were then determined analytically. Results of the in-situ contact angles from analytic solution performed on the experiment datasets ranging from 80.21° to 83.52° situated on partially water-wet side, confirming the a priori nature of the wetting state of the sand-pack. Consistency of the resulting in-situ contact angles was also examined with other relevant characterizations, including direct tomographic imaging and yet analytic wettability index. The analytic approach is well correlated with other methods, annotating a robust meaning of the proposed characterization. As water-wet contact angles, the results have an inversely proportional function with the oil recovery as reported in literature. The present analytical solution offers an alternative and yet unique approach to characterize in-situ contact angle, which should be used in simulation studies to further predict oil displacement.

Nanoparticles and low-salinity brines are of interest in oil recovery applications, although the main interfacial mechanisms governing their behavior remain controversial. While lowering the oil–water interfacial tension is desirable for EOR, many studies report the onset of a disjoining pressure between the oil–water and water–solid interfaces to significantly contribute to oil recovery via changing the apparent contact angle. In this study, wettability alteration was quantitatively examined by measuring the dynamic contact angle of a heavy crude oil droplet that was initially spread thinly on a glass substrate. The oil film was flooded with different displacing fluids: (i) synthesized surface-active nanoparticles (N-isopropylacrylamide, pNIPAM, 5 × 10–4 wt%); (ii) low-salinity brines (2000 ppm monovalent NaCl and divalent CaCl2); and (iii) blends of the nanoparticles and brines. For wettability alteration, the brines led to greater oil dewetting than nanoparticles, allowing lower steady-state contact angles (NaCl = 18.1°; CaCl2 = 27.2°) than the nanofluid (37.0°). These results from the hydration force generated by the hydrated salt ions which enhanced the oil displacement more than the nanoparticles structural force. Used alone, the polymeric nanoparticles bridged the oil droplet interface and substrate resulting in a dewetting hindrance. In the blend system, divalent salt ions were able to bind with the crude oil acidic species and solid substrate leading to reduced oil droplet dewetting (pNIPAM in CaCl2: 58.7°), regardless of the low oil–water interfacial tension (11.2 mN/m). On the contrary, for the monovalent salt (pNIPAM in NaCl), the combination of particle structural forces and brine hydration forces successfully displaced the oil droplet with fast receding rates which led to the gradual detachment (liberation) of the oil droplet from the substrate. These findings emphasized the minor role of the oil–water interfacial tension in both systems. However, they enhanced the fact that the disjoining pressure through both hydration and structural forces is a significant mechanism for an apparent wettability alteration.

Current theories about capillary pressure and saturation relationship (CPSR) in supercritical CO2-water system are based on measurement results under equilibrium state, which ignores the CPSR dynamic (transient) characteristics, leading to uncertainty in characterizing supercritical CO2-water flow (e.g., underestimating water saturation, overestimating production behaviors of producers, and so on). Consequently, to better understand the supercritical CO2-water flow and reduce uncertainty, it is crucial to study the CPSR transient characteristics. To reduce computational and experimental efforts, a machine learning approach, specifically, an artificial neural network (ANN), was introduced in this work to predict the dynamic capillary coefficient in supercritical CO2-water system by “learning” from available data. For the ANN, the input parameters consist of system temperature, water saturation, petrophysical properties of the porous media (e.g., permeability and porosity), and fluids properties (e.g., viscosities ratio of supercritical CO2 to water, and density ratio of supercritical CO2 to water), while the output parameter is the dynamic capillary coefficient. The results show that the dynamic capillary coefficient can be accurately determined through ANN modeling. In supercritical CO2-water system, dynamic capillary coefficient increases as the system temperature increases. Under a given water saturation, dynamic capillary pressure is larger than the equilibrium capillary pressure. Compared to the conventional CPSR measured under static state, the investigation conducted in this paper provides more valuable insights to the supercritical CO2-water system, which will be helpful for studying two-phase flow system in the context of geological carbon sequestration.

Networks of halite veins have been analysed along galleries of the potash Cabanasses mine (Súria anticline, SE Pyrenees). The presence of a shape preferred orientation cross-cut by halite veins suggests that the rocks hosting the veins underwent ductile deformation before fracture formation and healing. The petrographical characteristics of veins and host rocks, as well as the analysis of their bromine content, reveal that the vein-forming fluids likely resulted from pressure-solution and dynamic recrystallisation of the Lower Halite Unit rocks. Fluids at high pressure migrated upwards and were arrested at the Halite-Sylvinite Unit causing fracture formation below the Potash Unit, which acted as a seal and did not experience brittle deformation.

Muglad Rift Basin is the largest basin of Sudan’s interior basins, which covers around 120,000 km2 in NW–SE orientation, containing up to 13 km of Cretaceous-Tertiary continental sediments as a result of the extension due to the formation of Central African share zone. The mid-Cretaceous Bentiu and Aradeiba formations are the main reservoirs in Muglad Rift Basin that have been investigated by many authors over the last decade. Nevertheless, a detailed and precise analysis of the reservoir petro-physical properties such as porosity, permeability, electrical properties and water saturation is still needed. For these reasons, this study investigated the effects of diagenetic process in the Hamra East Oil field focusing on pores geometry classification and distribution in Bentiu and Aradeiba reservoirs. The analytical methods included well log interpretation, thin-section analysis, mercury injection porosimetry, electrical properties and a conventional air permeameter. The variation of facies association, reservoir properties, pore geometry and diagenesis process allows dividing Bentiu and Aradeiba formations into four reservoir units. Pores types vary from macropores (A), macropores (B) and mesopores, while the pore-throat size distribution varies from unimodal to trimodal. Scarce porosity/permeability in Aradeiba formation is due to precipitation of carbonate and clay minerals and compaction while high porosity/permeability in Upper Bentiu is due to dissolution of some detrital grains and authigenic cement.

Natural gas in a Natural Gas Field, a dry gas reservoir, northeast region of Thailand was investigated to determine the relationship of chemical species in order to predict phase behaviors using the thermodynamic simulation. Phase diagrams related to temperature (T) and pressure (P) dominate the phase behaviors of natural gas in the subsurface. The sub-chemical reactions were assumed by chemical relationships of their components which were similar to the chemical compositions of natural gas. Diagrams were generated from the thermodynamics simulation based on Peng-Robinson model combined with the Prode Properties program. Critical points as a function of mole fraction of methane were obtained by the phase envelope. Pressures at these critical points are mostly proportional to the increasing mole fraction of methane. The pseudocritical properties of temperature and pressure are related to the specific mole fraction of methane. Equilibrium conditions at this point are equivalent to methane mass. Pressures have more influence on methane (in reactant) at all chemical reactions. At approximately 0.75 mol fraction of methane, the P and T are limited with less than 22 MPa.a and 350 K, respectively. These associations are beneficial for predicting and controlling the phase behaviors in the petroleum reservoir.

The following study explained the ability to use natural additives for the inhibition of corrosion. There are a lot of corrosion failures being faced by petroleum companies, and there is a need for corrosion inhibitors which are effective to act to mitigate corrosion. While most inhibitors come with a limited and dedicated purpose which functions to limitedly serve the need of what it is used for, this work encourages the use of natural supplements toward its applicability as a drilling fluid additive. Studies on corrosion inhibition by natural supplements such as Fenugreek Leaves, Basil Seeds, Cumin, Aloe Vera gel, Sodium Polyacrylate, and Bora Rice solutions were performed experimentally on Mild Steel and Carbon Steel rod samples. Improvement in corrosion inhibition by these natural supplements was observed on the Mild Steel and Carbon Steel rod samples. The scope of using these corrosion inhibitors as a drilling fluid additive is supported by a few initial rheological tests for these natural supplements such as Aloe Vera gel, Fenugreek leaves, and Basil Seeds.

Carbon dioxide contaminates cement slurry and changes the hardened cement physical properties such as porosity, permeability and flow properties. The effects of additives such as diesel and lime in various proportions to the cement slurry to reduce the effect of the carbon dioxide contamination of cement slurry was studied. Also, the possibility of replacing the Portland cement with a white Portland cement was studied. The permeability of the carbonized cement was reduced, on the average for diesel cement and white cement given a minimum reduction of about 29.8% and 4.6% respectively when compared to the minimum porosity of carbonized Portland cement. This is a good indication that the addition of white cement and diesel as additives enhanced a good cement job in terms of sealing off unwanted zone. It was discovered that while diesel additive to the cement slurry has a positive effect on mitigating the effect of the carbon dioxide contamination; the addition of small quantities of lime has adverse effects on the cement if it is contaminated with carbon dioxide leading to the carbonization of the Portland cement. Therefore, whenever there is the possibility of carbonization of cement slurry, diesel cement is recommended to be used instead of the normal Portland cement. For all the additives, carbonization increased the porosity as compared to the uncontaminated cement and this is expected. Increased porosity due to the cement carbonization is a measure of weakened strength of the cement but the observed permeability when the used diesel or white cement is so small that there is possibility that the cement will retain its integrity of isolating unwanted zones. For improved strength, there is a need to add a strength improver to the cement slurry whenever there is a possibility of carbon dioxide contamination.

Tertiary sediments of KH-1 well Orange basin were examined by integrating organic geochemistry and microscopic observation. This approach assessed the characteristic attributes of organic facies including preservation settings and their importance to source rock potential. The examined samples have an average TOC value of 0.95% and this indicates a fair source rock potential. It has a good yield EOM (1119.46 ppm) with 32.20–39.39 wt.% hydrocarbon fractions. The relatively higher amount of phytane and low Pr/Ph ratio between 0.43 and 0.50, CPI (0.86–0.88), Pr/nC17 versus Ph/nC18 and C31R/C30 versus Pr/Ph low acyclic biomarker ratios reveal oxygen deficient marine environment as such good preservation of organic matter. Also, Pr/nC17 less than 0.5 depicts source rocks derived from open water conditions. The highly reducing marine conditions are ascertained by the absence of C19 tricyclic terpane, averagely high C25/C26 (1.32) tricyclic terpanes, low gammacerane index, averagely high C35/C34 tricyclic terpane ratio of 0.94. Sterane distribution confirmed the presence of planktonic land plant matter. Low concentration of ol/C30H signifies terrigenous inputs. Oleanane presence validates the sediments Tertiary age. The mean vitrinite reflectance values (0.852–0.862) show the samples are at the peak of oil generation. Both microscopic and geochemical maturity parameters show that the examined source rocks have a mature organic matter even though not buried deeper down for commercial hydrocarbon generation.

Kanikeh Formation in Central-Eastern Seram consists of interbedded sandstone, shale, and mudstone series. It is interpreted as the oldest sediments resting unconformably above the metamorphic basement. Sedimentation coincided with intra-cratonic rifting associated with north-western Australian continental margin. According to its lithological characteristics, Triassic Kanikeh Formation can be interpreted as a good petroleum system within Mesozoic in the area. The regional geological study, fieldwork (including measured stratigraphy), petrography, and geochemistry analyses have been conducted to reveal its potential for further hydrocarbon exploration. This study utilized seventeen outcrop samples from Kanikeh Formation for petrography and X-ray diffraction (XRD) analyses, whilst five samples were selected for total organic carbon (TOC) analysis. Petrographic data suggested that the samples are classified as quartz arenite, sublitharenite, lithic arenite, quartz wacke, lithic wacke, mudrock, and sandy micrite. Lithic arenite and lithic wacke are the most common sandstone types among the samples. Both petrographic and XRD analyses exhibit quartz abundance up to 50%. Porosity value of Kanikeh sandstone reaches more than 30% mentioned by a previous study is very encouraging. A very high TOC value (2.53 wt.%) of carbonaceous sandstone and shale indicates good preservation of organic matters. The measured stratigraphy of Bula area shows that the top of Kanikeh Formation becomes silt in size (fining upward). It may constitute a good seal rock for the petroleum system. Based on these results, Kanikeh Formation is considered a complete petroleum play.

In Tunisia, the Callovian Middle Jurassic series is believed to have oil-charged Jurassic-Cretaceous carbonate and clastic reservoirs such as those in the Ezzaouia and El Bibane fields. Accordingly, they are considered as a potential and promising source rock. Nevertheless, the maturity and petroleum potential of these intervals in various sectors are still poorly studied and are yet to be established. In this study, seven wells, spanning the Middle Jurassic series, and located in the northern part of southern Tunisia (Chotts Basin, Jeffara Basin, and south of Gulf of Gabes Basin), were evaluated. 1D BasinMod modeling was applied to evaluate the hydrocarbon generation and expulsion potential of the source rock via basin burial and thermal history reconstruction. The well lithological data and measured depths of each formation in a given well were introduced into the model to reconstruct their burial history. The depositional, non-depositional, and erosional events were estimated from lithostratigraphic data and well reports. Lithostratigraphic correlations between wells were established to better understand the structural architecture, the geodynamic evolution of the study area, and the lateral extension of the Middle Jurassic series. Source rock thermal maturity history was assessed by the integration of the geochemical data, various BHT (bottom hole temperature) temperatures, DST (Drill Steam Test) temperatures, Tmax temperatures, and vitrinite reflectance, into the BasinMod software. The critical moment of hydrocarbon generation, the timing of hydrocarbon expulsion, and generated and expelled HC quantities were estimated. Thermal maturity modeling results show that the Middle Jurassic source rock has reached the “oil window” in all wells (W1, W2, W3, W4, W5, W6, and W7). However, no well has reached the expulsion stage. This could be related to the fact that the modeled wells were all drilled on high structures. Further work is projected to model fictitious wells in grabens. The current results indicate an active Callovian source rock in the northern part of southern Tunisia.

Frontier basins are those basins on which available exploration data are very scanty. Although data on Nigeria’s frontier basins were very scanty many years ago, significant volumes of R&D and industry/operators data have progressively accumulated. Such generated and/or scouted data have helped greatly to de-risk and mature many of the listed frontier basins. Nigeria’s frontier basins comprise the Anambra Basin, Benue Trough (lower, middle, upper), Bida Basin, Chad Basin (Nigerian sector), Dahomey Basin, Sokoto Basin and the deep and ultra-deep Niger Delta offshore. Overwhelmingly, research results along with operators’ engagements have graded the basinal maturity vis-a-vis the risk elements into the low-risk Anambra and Dahomey Basins where there are operators engagements and discoveries (Orient Petroleum, Yinka Folawiyon), moderate risk Benue Trough and Chad Basin, where NNPC is actively engaged with significant success in the Gongola Sub-Basin, and high-risk Bida and Sokoto Basins where there are presently no operators, but rather an active data generation by researchers and data gathering by the NNPC. The status of the deep and ultra-deep offshore is not certain. Many of the risk elements may be downgraded with committed exploration programmes of the Nigerian National Petroleum Corporation and the increased funding to R&D by the Corporation and other sources. Research results from different sources are presented in the paper to elucidate our current knowledge of the frontier basins.

The abstract points out relationships between intrusive processes and hydrocarbon saturation in the Siberian platform. Located around the periphery of the Tunguska synclinorium (especially to its south and south-east) are large hydrocarbon pools: Kuyumbinskoe, Paiginskoe, Chonskoe and many others. These deposits are confined to the Riphean, Vendian and lower Paleozoic strata making up the lower structural tiers of the platform cover. Early Triassic basaltic rocks interstratified with this sequence comprise a mix of sills, dikes and stocks. Together, these basaltic rocks make up a large igneous province (LIP). These geological bodies are paragenetically associated with manifestations of trap volcanism. Using the southwestern part of the Siberian platform as an example, the influence of early Triassic magmatism on oil and gas reservoirs has been modelled in 3D to help us better understand the petroleum system in this region and the way the hydrocarbons were generated and accumulated. Based on our modelling, we calculated the transformation ratio of organic matter in source rocks as well as the history of hydrocarbon generation.

Hydrocarbon reserves from the explored traditional traps of oil and gas at depths of up to 3 km, which are characterized by a low level of production costs, are now practically exhausted. It is necessary to make a choice of the direction of conducting prospecting and exploration works, while being guided by the criteria of the cost price of oil and gas production. Against the background of very costly work on the production of hydrocarbons from hard-to-recover reserves, resources of shale formations and shelf deposits, the global phenomenon of trap magmatism, especially within ancient platforms, opens up prospects for involving significant volumes of sedimentary strata at relatively shallow depths in oil and gas exploration studies, which will allow to open fairly cheap oil and gas reserves.

An Chau Basin extends on the northeastern land part of Vietnam, with an approximate area of 10,000 km2. Devonian and Triassic core shale and outcrop samples, obtained from sixteen shallow wells and field works in this basin, were performed using geochemical and x-ray diffraction tests. This study aimed to predict shale gas potential based on the results of Rock–Eval pyrolysis, vitrinite reflectance, visual kerogen typing and mineral compositions. The shales consist of gas prone to inert terrestrial organic matter that reached the uppermost limit of the gas window (Ro > 2.33%, TAI > 3.3). The over maturity is likely to cause poor hydrocarbon generation potential of proposed type III/I kerogen, showing low to moderate TOC contents of 0.04–3.58 wt% and poor product yields S2 < 1 mg HC/g rock. Only about 40 m shale cores in the Triassic formation have average HI of about 229 mg HC/g TOC and entered dry gas window with an average vitrinite reflectivity of 2.35%, respect for shale gas potential. Most shales are dominated by brittle minerals such as quartz and carbonates, supposed to be favorable to shale brittleness. A clay-fraction is dominated by illite, chlorite and kaolinite, whereas, the smectite is almost transformed into illite–smectite and chlorite-smectite and organic matter predictably reached above 130 °C. The findings show that Triassic shales that are only present in local area show negligible shale gas potential. Therefore, the prospective areas need to be explored further for the complex geology structures of the neighborhood such as Ha Noi Trough and Song Hong Basin.

Horizontal well drilling and hydraulic fracturing were implemented to enhance the economic development of shale gas formations. Thus, the consideration of the gas flow patterns in the rock reservoir formation is essential to ensure that the gas production from these formations is improved properly. Typically, the reservoir boundaries are considered to be sufficiently sealed for developing models to maximize the gas production from shale formations that act as a non-flux boundary. Nonetheless, sealed faults and normal fractures in the shale reservoir could be reactivated during hydraulic fracture stimulation, which can lead to changes in boundary conditions. This scenario was conducted in this paper. The simulation was sized at the production stage for computational implementation. A new approach to model fractures in the formation using the semi-explicit method of horizontal layers and the well stimulation technique was introduced in this research. The relation between the impact of permeability change and boundary conditions were different in the domain. COMSOL Multiphysics 5.1 was used to solve the flow equation; moreover, the numerical simulation of pressure dissipation and gas flowing motion in the shale gas fractured was addressed. The research results reveal that in the existence of a fault across the structure boundaries, of the non-flux maximum was rendered to forecast the gas production rate values and neglect the leak-off values that can be correlated with some fault around the boundary.

The intracratonic Ghadames Basin of South Tunisia is believed to have undergone several tectonic phases but the Hercynian phase is considered to be the most important given the amount of eroded sediment extending from Devonian to Permian. The basin encompasses two main supplying source rocks thought to have impregnated Paleozoic and Triassic reservoirs which are the Early Silurian Tannezuft source rock (hot shales) and the Middle-Late Devonian Aouinet Ouenine source rocks. The latter was probably the least appraised from a publication point of view. This research focused on the Devonian Aouinet Ouenine source rocks and tried to model their burial and thermal history and estimate the generated and expelled hydrocarbon amounts. An evaluation of non-conventional remaining hydrocarbon was also attempted. To this end, around thirty wells where source rocks were crossed were scrutinized. Various lithostratigraphic correlations were achieved based on thorough subdivision of the Aouinet Ouenine Group into four formations (AO I to AOIV). Aouinet Ouenine II (AOII) and Aouinet Ouenine (AOIII) formations were considered as being fairly to highly rich in organic matter and bear a good source rock potential. The N-S lithostratigraphic correlation, particularly, shows noticeable thicknesses variation of the Aouinet Ouenine group, thinning from South to North under the effect of the Hercynian unconformity. Burial and thermal modelling using the BasinMod software was performed via the integration of lithostratigraphic data, thermal data, known tectonic events, and geochemical data. The modelling allowed us to quantify the amounts of generated and expelled hydrocarbons and subsequently estimate the potential of oil left in place. Results show that the main source rock formations (AOII and AOIII) have generated average amounts of hydrocarbons and expelled only very small quantities, given the expulsion threshold that was not reached (SATEX = 11%). Approximately, it was estimated that the Aouinet Ouenine II Formation may still contain in the order of 73.68 × 109 bbls of oil in place, while the Aouinet Ouenine III Formation could still contain 62.9 × 109 bbls of oil in place. These reserves could be exploited as shale oil and constitute good amounts of unconventional reserves to be recovered.

The heat injection well or subsurface heater temperature plays an important role during the in situ conversion process (ICP) of oil shale formation because of the strong temperature dependency of pyrolysis of solid kerogen into fluid. The oil and gas generation and production are greatly affected by heater well spacing too. In this paper, a reservoir simulation model of oil shale ICP was generated which incorporated all the complicated processes of heat dissipation through oil shale’s porous medium, the transportation of heat through the fluid, temperature-dependent chemical reactions, oil and gas generation through solid kerogen and production of these oil and gas, was generated. The outcomes of the simulation model were further used to explore the relationship between cumulative hydrocarbon production time and heater wells spacing. The results showed that the generation of hydrocarbon fluid through solid-phase kerogen is strongly temperature-dependent process. As a result, with the decrease in heating temperature or increase in heater well spacing, the oil rate peak noteworthy decreases and the production time is delayed. Additionally, both of lowering down the heating temperature or increasing the heater well spacing also affect (reduce) the cumulative hydrocarbon production. But the ultimate hydrocarbon recovery is expected to be equal if the simulations are performed over a very long time period. This work introduced a set of detailed simulation studies to examine the scenarios or conditions that may be responsible for different production times as a function of heater wells spacing during the oil shale ICP. The results revealed that the ICP is a strong heater wells spacing dependent process.

Petroleum consumption can be a powerful indicator of economic performance for many countries throughout the globe. The Coronavirus spread across the world rapidly, causing hundreds of thousands of deaths. Its impact on the global economy, and specifically petroleum industry has been significant. This study analyzes the relationship between petroleum consumption and the impact of the Coronavirus pandemic spread on global economies. Statistics on petroleum consumption before and after the onset of the Coronavirus pandemic were analyzed for eight countries around the world: Canada, Mexico, United States of America, Brazil, Russia, China, Japan and India. The percentage decrease in petroleum consumption was calculated. From January to April 2020, a steady decrease in petroleum consumption was observed for all the countries in this study, except China. In the case of China, petroleum consumption decreased from January 2020 to March 2020, and began to slowly increase from April 2020. Petroleum consumption data were similarly analyzed for different geographic regions throughout the world, as well as global consumption. % decrease (or increase as the case may be) in petroleum consumption is an effective indicator of the change in economic performance for most countries, and it may be used as a qualitative/semi-quantitative parameter of economic recovery in the aftermath of the Coronavirus pandemic.

The method of secondary recovery (water injection and gas) plays an important role in oil production. They maintain the reservoir pressure to support production and ensure the scanning of the oil to increase the recovery rate. However, over time they create big problems. Our job is firstly, to study the secondary recovery processes and adverse effects (theoretically), then we studied the water injection problems, water breakthroughs in the well OMJ723 and presented methods to solve these problems. So, our work focused on evaluating the use of MPBT as a solution for water breakthroughs. After the installation of this tool and the completion of the Wetter Shut-off on 06/02/2016, we noticed a drop in water production of Wc = 60% up to Wc = 15%, but causing a drop in the production of car oil isolated the two water producers and also banned 3396–3402 which produced only 6.40% of the water.

Sensitivity analysis study for production optimization and recovery of lost condensate with gas-injections play vital role in enhancing-condensate recovery during the field development to yield optimum profit. In gas cycling, gas is effectively miscible with condensate and its viscosity is reduced, which eventually decreases the residual-condensate-saturation and recovers the lost condensate with an optimum gas production. In this work simulation of the single-layer heterogeneous–gas condensate reservoir was modeled in a compositional simulator to highlight the reservoir and fluid properties characteristics. Then a production development study of gas cycling and CO2 injection was analyzed to understand which method is the most optimal and economically feasible to recover the lost condensate and increase the ultimate productivity yield. An injection patterns study of five-spot and nine-spot with gas cycling has been carried out with the analysis of impact of injection patterns on enhancing-condensate recovery and optimizing the project economically. Nineteen years of gas cycling applied with five-spot and nine-spot pattern flooding improved condensate recovery by 41%. The results also proved that the selection of optimum well spacing can help to best select flooding pattern in order to optimize a field development plan for the gas condensate reservoir. Here, an in-depth sensitivity study for the production optimization of gas cycling five-spot with optimum well spacing plans was introduced; CapEx for drilling number of injection-production wells is the influencing factor found in this study. The relationship between well spacing and number of wells was also studied to evaluate the impact of the applied capital expenditure (CapEx) and operating expenditure (OpEx) upon the Net Present Value (NPV) with optimal injection pressure, injection flow-rate, and production time.

The work done in response to the accident that occurred in Gran Tarajal Harbour could offer a different way to solve similar accidents. Three new developments were used to reduce the environmental impact and the odour disturbances due to population to almost zero. The three new technologies were: Reusable sponge absorbents, granulate absorbents, and bioremediation with specific allogenic bacteria. Using foam reusable absorbents, it was possible to recover 57 ton of hydrocarbon with less than 5% of water in three days, relying on 8 people without previous training. Foam has a very high hydrophobic and oleophilic capacities, 1 kg removes up to 30 kg of oil, and after a quickly squeeze, it recovers its initial capacity to absorb oil. Then 1 kg of sponge can remove more than 6 ton of oil, because it is possible to reuse 200–300 times. Second technology is a granulate with a great hydrophobic and oleophilic capacities, which allows cleaning all the surfaces, tools, globes, boots, floor, and avoid the spills from harbour to reach back the water surface, when pieces of wrecks or machinery plenty of oil were recovered by cranes from water. The third development was bacteria, Pseudomona putida, which degrades oil very quickly. It reduces the hydrocarbon viscosity and surface tension, which means a reduction of oil adherence to sand, rocks, walls, organisms’ skins, and other surfaces, reducing environmental impact. This property allows increasing the lixiviation process from the sand, gravel, and muds to surface, and a constant degradation of oil attached to surfaces.

Due to its particular tectonic position in the North African margin, the geological history of Tunisia strongly depends on the relative motion of the African plate, especially since the Jurassic period as a result of the Tethyan opening followed by the Mesogean opening during the Cretaceous period. This extensional regime was followed, during the Late Cretaceous by a compressive pulsation, subject to a controversy among many authors. In order to characterize this pulsation, a study based on the analysis and interpretation of seismic profiles chosen in the southern part of the gulf of Gabes has proven that this Pyrenean event is diachronous. This diachronism could be explained by the resumption of an active halokinetic activity that marked the concomitant sedimentation of the Upper Cretaceous-Paleogene. The initiation and the diachronism of the halokinetic activity are caused by a differential sedimentary loading (downbuilding) spread over time. The latter was triggered since the Senonian distension. However, this diachronism seems to be amplified by a compressive pulsation that marked the terminal Cretaceous.

Salt domes are diapiric structures associated with various hydrocarbon and mineral resources (i.e., oil and gas, Pb–Zn deposits, halite and native sulphur). Surface and subsurface (boreholes and geophysical) data on the salt structures of the Tebessa region in the Northeast of Algeria allowed us to approach the anatomy of these structures and study the petrographic and geochemical characteristics of these evaporitic rocks. The salt stock consists of grey or red halite containing anhydrite, magnesite, and dolomicrite constituting an insoluble residue and up to 20% of the volume of the rock. It is often surmounted by a “cap-rock” made up of a brecciated anhydritic zone of about twenty metres thick and a gypsiferous zone also brecciated with a thickness of up to a hundred metres. The calcitic zone, often present in the American cap-rocks of the Gul-Coast, has not been observed in this region of north-eastern Algeria. The geochemical data made it possible to highlight the particularities of these Triassic evaporite rocks and underline the similarities and the differences with the Tunisian and American domes. The calcite zone as well as the Pb–Zn mineralization, generally linked to the American cap-rocks, were not observed. This difference could be due to the absence of hydrocarbons necessary for their genesis.

The opening models of the Tethys between Gondwana and Eurasia are evidenced by several geological models. However, the embryonic phases of this evolution remain unknown due to the rarity of tectono-sedimentary facies. Located in the southern Tellian margin, the Ouarsenis Mountains exhibits an excellent zone where Mesozoic tectonic events are well recorded in the rocks. This area seems to be affected by N90, N120, and N140-trending fault systems. N10, N40, and N70 strike-slip faults are also characterized in this region. Generally, faults are often marked by uplift of Triassic saline material and there are associated with different structures: (i) monocline structures with a strong dip of 80° S, 70° E, and 60° SE respectively at the East, to the south and to the center, (ii) inverted structures (Grand Pic and Bou Malah), and (iii) Liassic formations revealing tectono-sedimentary events from the lower to middle Jurassic where extensional tectonic regimes persisted. A polyphase salt tectonics is observed in the whole of the Ouarsenis Mountains, the effects of which begin from the lower Liassic and continue until the upper Cretaceous related to the first tectonic stage of the Tethyan rifting. The Cenozoic tectonic stage which takes over, gives the current landscape of Ouarsenis. The deformation observed in the Ouarsenis region was interpreted for a long time as the results of compressional tectonic. This new study highlighted the role of diapiric events during the lower–middle Jurassic, reactivated along a main tectonic blocks. The Alpine tectonic inversion is mainly observed at the southern areas of the Tethys Sea. This new interpretation allows us to better explain the Ouarsenis Mountains with introducing the former Mesozoic tectonic inheritance and diapiric activity.

A brief methodological analysis of the main ideas, approaches, and directions, which may be used to create a new whole paradigm in global tectonics, was suggested. The main ideas are: forcing downward from higher to lower geosphere and the large role of Moon’s tides for tectonosphere. So any processes in the mantle as convection, etc. are of small value. The heuristic comparison shows that most perspective approaches in global tectonics are rotational. The basic theses of new Paradigm were proposed for discussion.

The main objective of this work is to highlight the contribution of micro and macrotectonic in the characterization of the tectogenesis of the atlasic folds of the Central-Southern Atlas. Fieldwork carried out in the NE-SW asymmetric anticline of Jebel Meloussi shows numerous micro and macrotectonic deformations. The examination of these structures allows us to determine extensional synsedimentary tectonic deformations as well as deformations related to late compressive tectonics. The highlighted synsedimentary deformations indicate an extensional tectonics during the Cretaceous. This tectonic involves five major NW-SE to submeridian faults: the Ein el Karma fault, the Khanguet Zebbag fault, the Ein Jebs Fault, the Zefzef Fault, and Remilia Fault. The studied microtectonic stations contribute to qualify the tectonic fracturation. The resulting stress tensors from this fracturation confirm an atlasic to post-Villafranchian phases responsible for the major folding.

The relevance of this study is due to the need to present a new important discovery about the structure and evolution of the North continents from the Hadean till Holocene. The reality of the Earth’s megacontinent has been proved on the basis of the planetary seismic sections. It was initially formed in a huge deep three-beam depression on the Earth’s surface. Ancient crystalline basement of the megacontinent was formed in the Hadean and Archean time. Some of its parts periodically descended and rose in the subsequent geological time. In the Pleistocene, the megacontinent was a fully elevated land and the Arctic great glacier had formed on it three times. Towards the middle of the Holocene, the Arctic and Indonesian lowland sectors of the megacontinent were flooded after the sharp sinking of the Arctic central part and the rise of the Ocean level by 120 m. The increased oceanic space divided the single megacontinent into three large modern continents—American, Eurasian-African, and Australian.