Search

Carbonate rocks are important for the petroleum industry, as they contribute significantly to hydrocarbon reserves, although their analysis is complex due to the high cost of core sampling and their high heterogeneity; for this, synthetic rocks aim to provide relatively homogeneous samples with analogous characteristics to natural rocks. In this research, synthetic carbonate rocks were produced by mixing a fixed ratio between limestone powder, obtained from limestone mining waste, and epoxy resin as a cementing material, using compaction energy for consolidation. The work aimed to produce homogeneous samples with high strength, reproducing the intergranular pore system for future applications in rock–fluid interaction analysis. The characteristics and structure of the samples were investigated through X-ray computed microtomography, petrographic images, petrophysical, chemical and geomechanical tests. Results showed a direct increasing relationship between porosity and permeability and a tendency for mechanical strength (UCS) to decrease with increasing porosity. When compared with the natural carbonate rocks, these presented similarities in their mechanical properties and petrophysical measurements, showing that the methodology can be considered as an alternative for the obtention of a realistic material that can be used for future experiments regarding rock mechanics and rock–fluid interaction for prediction of carbonate rocks' behavior. [ABSTRACT FROM AUTHOR]

Copyright of Geominas is the property of FUNDA-GEOMINAS. (Fundacion de Egresados d Amigos de la Escuela de Ingenieria Geologica y de Minas) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Abstract The integration of multiscale datasets, including seismic, well-logs and stratigraphy, is providing a precise picture about reservoir evaluation and spatial distribution. This study focuses on the seismic interpretation and sequence stratigraphic analysis of the Bahariya Formation in the South Umbaraka oilfields (Selkit, Khepri, and Sethos), located in the Western Desert of Egypt. Seismic interpretations reveal various structural closures, including anticlinal domes and faulted anticlines in different fields. The study area is divided into northern and southern blocks separated by a major fault, and structural cross sections provide valuable information on reservoir zones regarding lateral extension, thickness variation, and fault distribution. The Bahariya Formation is subdivided into two depositional sequences: Lower Bahariya sequence (BAH.SQ-1) and Upper Bahariya sequence (BAH.SQ-2) with distinct wireline-log characteristics, seismic reflections, and lithofacies variations. BAH.SQ-1 comprises mixed siliciclastic-dominated units with some carbonate units, while BAH.SQ-2 consists of mixed siliciclastic and carbonate units. Multiple sequence boundaries, depositional surfaces, and systems tracts are identified within BAH.SQ-1 and BAH.SQ-2, indicating changes in sedimentary environments and sea-level fluctuations. The petrophysical evaluation reveals promising reservoir zones in both the Lower and Upper Bahariya sequences. However, the Lower Bahariya sequence exhibits superior reservoir characteristics in terms of net-pay thickness, shale volume, effective porosity, and water saturation. Particularly, the sandstone-dominated LST-1 within the Lower Bahariya Formation is identified as a favorable reservoir zone. Conversely, the Upper Bahariya Formation has limited reservoir potential. This study underscores the significance of sequence stratigraphy and reservoir architecture, emphasizing the role of faulting, folding, and depositional environments in the distribution and quality of reservoir zones. The findings contribute valuable insights into the structural and stratigraphic characteristics of the Bahariya Formation, enhancing understanding of hydrocarbon plays and reservoir distribution in the studied area.

Carbonate rocks are important for the petroleum industry, as they contribute significantly to hydrocarbon reserves, although their analysis is complex due to the high cost of core sampling and their high heterogeneity; for this, synthetic rocks aim to provide relatively homogeneous samples with analogous characteristics to natural rocks. In this research, synthetic carbonate rocks were produced by mixing a fixed ratio between limestone powder, obtained from limestone mining waste, and epoxy resin as a cementing material, using compaction energy for consolidation. The work aimed to produce homogeneous samples with high strength, reproducing the intergranular pore system for future applications in rock–fluid interaction analysis. The characteristics and structure of the samples were investigated through X-ray computed microtomography, petrographic images, petrophysical, chemical and geomechanical tests. Results showed a direct increasing relationship between porosity and permeability and a tendency for mechanical strength (UCS) to decrease with increasing porosity. When compared with the natural carbonate rocks, these presented similarities in their mechanical properties and petrophysical measurements, showing that the methodology can be considered as an alternative for the obtention of a realistic material that can be used for future experiments regarding rock mechanics and rock–fluid interaction for prediction of carbonate rocks’ behavior.

The offshore part of the Nile Delta Basin (NDB) is a prolific provenance for gas exploration. The present study aims to perform a geophysical evaluation for the Messinian Abu Madi sandstones along the Messinian paleo-valley in Baltim field as a case study. The seismic interpretation step exposed that the Abu Madi incised valley displays NNW-SSE trend with width ranges from 5 to 8 km and a length of 32 km. The petrophysical appraisal for five drilled wells (BE-2, BE-3, BE-5, BN-1 and BN-2) in Baltim Field has been performed. The findings of this assessment revealed that the most promising intervals in the studied wells have gross-thicknesses vary between 25 and 49 m; net pay thicknesses range within 15 m and 38.5 m; net/gross ratio of 0.54–0.90; effective porosity of 15–40%; shale volume is less than 20; and water saturation ranges between 25 and 50%. Such notably talented and converging values of these parameters across the examined zones reflects the relative homogeneity and lateral continuity of the Abu Madi reservoir across the inspected paleo-valley. The results of this study can help for a better understanding of the petrophysical characteristics for the Messinian reservoir over the offshore NDB. Therefore, the Messinian sandstones could exhibit possible targets for future gas exploration over the offshore NDB together with the Pliocene sandy levels, which represent the main and the recent discoveries of gas accumulations. [ABSTRACT FROM AUTHOR]

Understanding basic petrophysical properties may enhance the recovery of residual oil saturation and help in reservoir management. Reservoir oil saturation is the fraction of the porosity of a zone occupied by oil. The trapping may increase with the increase of porosity. Oil reservoirs represent a significant fraction of the reservoirs in the world-wide. We try to make a reservoir evaluation using petrophysical analysis of well logs and core samples at Issaran Field, South Gharib Formation, West of the Gulf of Suez, southeast Egypt. This area was heavily influenced by the structural setting of the Gulf of Suez's central province, which is characterized by major SW dipping faults with a regional stratigraphic dip toward the NE. The high structural blocks are located in the center of the research area, and the low structural region is located in the southwest. South Gharib Formation is primarily composed of carbonates with few sulfates that grade upwards into sulfate-rich beds in the upper part. Laminated dolomitic limestone, with evaporites grades, changes downward into laminated dolomitic limestone and marly limestone, in the lower part. The anhydrite and dolomite units near the bottom have spotty oil stains. The structural setup is continued by the spread and deposition of this formation. We try to make analytical examination, of some reservoirs, accomplished by analyzing both well log data and core rock samples, vertically and laterally. According to the study of the horizontal permeability to vertical permeability ratio (Permeability anisotropy; λ k ), the reservoir is laminated rock ( λ k = 1.1 - 5 ), with a few data samples nearly isotropic ( λ k = 1 / 1.1 –1.1) and fractured ( λ k = 1 / 2.5 –1/1.1). Reservoir data histograms show that the most typical values of the data are 20–30% oil saturation and 7–10% porosity. The net-pay zone varies from four to 71 feet at different depths (897–1414 feet). Due to low shale content, water saturation, high effective porosity values, hydrocarbon saturation, may show higher net-pay thickness. These results may help to enhance the oil recovery. The area in the middle of the research area is suggested for future hydrocarbon development and using more petrophysical analysis. [ABSTRACT FROM AUTHOR]

Characterization of reservoir petrophysical properties provides critical insights into reservoir deliverability and field development strategy. The main objective of this work is to present a comprehensive core-based petrophysical assessment of the Cenomanian Bahariya Formation and the Turonian Abu Roash (AR-D and AR-E, respectively) Members of the Abu Gharadig field situated in the Western Desert, Egypt. The AR-D is water-wet and consists of micro- to mesoporous shallow marine limestone lithofacies with moderate porosity (Φ), poor horizontal permeability (Kh) with poor permeability anisotropy due to the presence of vertical fractures, while the nano- to mesoporous argillaceous limestone lithofacies is very tight. Both the lithofacies exhibit primary and secondary depositional fabrics. Overall, the AR-D member exhibits impervious to poor reservoir quality, and so a suitable stimulation strategy will be essential to produce from this interval. The AR-E interval implies a tidal depositional environment. The calcareous sandstone lithofacies of the AR-E is macro- to megaporous and exhibits moderate to high porosity (> 15%) and excellent permeability (up to 305 mD). The meso- to microporous glauconitic siltstones of the AR-E have poor porosity and permeability. Both lithofacies are characterized by high water saturation, preserve primary depositional fabrics and consist of isotropic pore system along with some connected horizontal pores yielding higher permeability anisotropy. The Bahariya Formation consists of fine to medium grained massive sandstone lithofacies with minor siltstone intercalations, indicating a channel deposit in a coastal or fluvio–deltaic environment. It exhibits high porosity (~ 20%) and permeability (up to 649 mD) but shows very high water saturation. It preserves the primary depositional fabrics with isotropic pore system. The thin siltstone intercalations may act as vertical barriers. Based on the petrophysical assessment, we made recommendations on the reservoir development aspects. [ABSTRACT FROM AUTHOR]

The current work assesses the sandstones of the Mutulla Formation as well as the limestone of the Thebes Formation for being promising new oil reservoirs in Rabeh East field at the southern portion of the Gulf of Suez Basin. This assessment has been achieved through petrophysical evaluation of wireline logs for three wells (RE-8, RE-22 and RE-25). The visual analysis of well logs data revealed that RE-25 Well is the only well demonstrating positive criteria in five zones for being potential oil reservoirs. The favourable zone within Thebes Formation locates between depths 5084 ft and 5100 ft (Zone A). However, the other positive zones in Mutulla Formation occur between depths: 5403.5–5413.5 ft (Zone B), 5425.5–5436 ft (Zone C), 5488–5498 ft (Zone D) and 5558.5–5563.5 ft (Zone E). The quantitative evaluation shows that the Zone A of Thebes Formation is the best oil-bearing zone in RE-25 Well in terms of reservoir quality since it exhibits lowest shale volume (0.07), minimum water saturation (0.23) and lowest bulk volume of water (0.03). These limestone beds include type of secondary porosity beside the existing primary porosity. On the other hand, the sandstones of Mutulla Formation in RE-25 contain four reservoir zones (B, C, D and E) with the total net pay thickness of 35.5 ft. Moreover, the obtained results revealed that it is expected for zones B, C and D to produce oil without water but Zone E will produce oil with water. [ABSTRACT FROM AUTHOR]

Copyright of Acta Sedimentologica Sinica is the property of Acta Sedimentologica Sinica Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Petrophysical properties including pore structure and permeability are essential for successful evaluation and development of reservoirs. In this paper, we use casting thin section and mercury intrusion capillary pressure (MICP) data to investigate the pore structure characterization, permeability estimation, and fractal characteristics of Carboniferous carbonate reservoirs in the middle blocks of the eastern margin of the Pre-Caspian Basin. Rock casting thin sections show that intergranular and intragranular dissolution pores are the main storage spaces. The pore throats greater than 1 μm and lower than 0.1 μm account for 47.98% and 22.85% respectively. A permeability prediction model was proposed by incorporating the porosity, Swanson, and R35 parameters. The prediction result agrees well with the core sample data. Fractal dimensions based on MICP curves range from 2.29 to 2.77 with an average of 2.61. The maximum mercury intrusion saturation is weakly correlated with the fractal dimension, while the pore structure parameters such as displacement pressure and median radii have no correlation with fractal dimension, indicating that single fractal dimension could not capture the pore structure characteristics. Finally, combined with the pore types, MICP shape, and petrophysical parameters, the studied reservoirs were classified into four types. The productivity shows a good correlation with the reservoir types. [ABSTRACT FROM AUTHOR]

As a major supplement to conventional fossil fuels, unconventional oil and gas resources have received significant attention across the globe. However, significant challenges need to be overcome in order to economically develop these resources, and new technologies based on a fundamental understanding of flow and transport processes in unconventional reservoirs are the key. This special issue collects a series of recent studies focused on the application of novel technologies and theories in unconventional reservoirs, covering the fields of petrophysical characterization, hydraulic fracturing, fluid transport physics, enhanced oil recovery, and geothermal energy.

Despite the economic importance of the Waihapa Field in Taranaki Basin in New Zealand, the structural setting, petrographic and petrophysical properties of its Cenozoic reservoirs are still poorly understood. This research integrates a 3D seismic survey with core and well logs data, as well as petrographic description in order to discuss the structural setting and the reservoir characterization of the Cenozoic reservoirs along the Waihapa Field, Taranaki Basin, New Zealand. A major thrust fault was interpreted dissecting both the Kapuni (Paleocene- Eocene) and Ngatoro (Oligocene- Early Miocene) groups and another opposite thrust fault affecting the Ngatoro Group and the Waihapa anticline. These compressional structures were resulted from the regional compression which affected the Taranaki Basin during the Miocene. Wai-iti Group (Miocene) is dissected by a set of NE-SW normal faults. These normal faults remark the end of the compressional phase and the beginning of a new extensional phase along the Taranaki Basin. The petrographic data of the studied reservoirs indicate that the Late Miocene Mount Messenger Formation is composed of feldspathic wacke, micaceous feldspathic quartz arenite and mudstone microfacies, whereas the Oligocene Tikorangi Formation is composed of five microfacies (bioclastic grainstone, bioclastic packstone, sandy wackestone, highly fractured silty mudstone and sandy glauconitic packstone microfacies). Downward, the Upper Eocene Mangahewa Formation is composed of ferruginated quartz arenite, micaceous quartz arenite, and ferruginated calcareous quartz arenite microfacies. Cementation and compaction are mostly affected the Mangahewa Formation while fracturing and dissolution are primarily affected the Tikorangi and the Mount Messenger formations respectively. The studied core data was discriminated into four petrophysical static rock types (PSRTs). The PSRT1, representing the Mount Messenger reservoir, has the best reservoir quality (av. porosity = 23.3%, av. permeability = 45.0 md, and meso pores, 2.60 μm) while the PSRT4 of Tikorangi Formation has the lowest reservoir quality (av. porosity = 5.5%, av. permeability = 0.01 md, and nano pores, 0.07 μm). The PSRT2 (av. porosity = 4.17%, av. permeability = 0.26 md, and micro pores, 0.59 μm) and PSRT3 (av. porosity = 5.93%, av. permeability = 0.08 md, and micro pores, 0.22 μm) are petrophysically considered transitional rock types between the PSRT1 and the PSRT4.However, Tikorangi reservoir is already producing oil from the borehole scale fractures. This work represents the workflow applied during integrating seismic, petrographical and petrophysical data in order to characterize carbonate and clastic reservoirs for any further hydrocarbon development plans along the field. • Seismic interpretations allowed delineating structural features and tectonic implications of Waihapa Field in Taranaki Basin. • Application the 3D seismic attributes and synthetic seismograms plays a vital role in determining the geologic regime. • Integrated well log and core interpretations allowed defining several clastic and carbonate microfacies of the reservoirs. • The studied reservoirs have been successfully divided into petrophysical static rock types (PSRTs). • Good reservoir quality has been assigned to the Mount Messenger, Mangahewa, and Tikorangi Formations. [ABSTRACT FROM AUTHOR]

In order to characterize the petrophysical properties of shale using NMR technique, eight shale samples from the Lower Cambrian Qiongzhusi Formation in the eastern Yunnan province were measured by porosity and permeability tests, field emission scanning electron microscopy (FE-SEM) and NMR experiment. Pore types were obtained from the shape and distribution of transverse relaxation time (T 2 ) spectrum. Residual porosity and movable porosity could be well estimated based on T 2 spectrum area fraction. On the basis of Coates model, we proposed a regional Coates model to calculate the NMR permeability of shale. A method for determining T 2cutoff of shale samples was also expounded. Moreover, the specific surface area distributions and pore size distributions could be obtained based on the mathematical equation of T 2 . Results show that T 2 spectrums of shale samples at water-saturated condition can be divided into unimodal and bimodal T 2 spectrums. Continuous bimodal T 2 spectrums reflect the samples with good connectivity between small pores and large pores, whereas discontinuous bimodal T 2 spectrums reflect that the connectivity between small pores and large pores is poor. Shale samples with higher bound water content have a greater T 2cutoff . The NMR permeability is close to gas log permeability, which proves the applicability of regional Coates model. In eight shale samples, transition pores account for the largest proportion, followed by mesopores, indicating that transition pores and mesopores are the major sites for the accumulation of shale gas. [ABSTRACT FROM AUTHOR]

The Abu Madi sandstones represent the largest gas-bearing reservoirs in Nile Delta Basin of Egypt. This paper aims to perform a sequence stratigraphic analysis besides petrophysical appraisal for the Abu Madi Formation along the Messinian incised valley. Eight facies types (F1–F8) are identified in the Abu Madi Formation, ranging in lithology from sandstone, siltstone, shale and mudstone with different sedimentary structures trough/planar cross-bedding, ripple laminated/laminated and massive. The sequence stratigraphic analysis for thirteen wells extends in both offshore and onshore parts of this incision revealed that the Abu Madi Formation is divided into two depositional sequences: LMDSQ-1 (lower Abu Madi) and LMDSQ-2 (upper Abu Madi). The findings of the petrophysical assessment exhibit that the favorable gas intervals in each depositional sequence correspond the sandstones of the lowstand systems tract (shale content: 4–22%; effective porosity: 12–27%; water saturation: 20–63%) rather than the highstand systems tract or the transgressive systems tract (shale content: 5–30%; effective porosity: 7–20%; water saturation: 30 and 53%). The entire sandstones of the LSTs comprise four reservoir rock types: trough/planar cross-bedded sandstones (Type-1, F1), parallel-laminated sandstones (Type-2, F2), massive sandstones (Type-3, F5) and ripple cross laminated sandstone/siltstones (Type-4, F3). The massive sandstone (Type-3) is the best reservoir type since it contains interparticle pores with porosity up to 26% and horizontal permeability varies between 460 mD and 1439.37 mD. However, the ripple cross laminated sandstone/siltstones (Type-4) have the worst reservoir type, with an average porosity of 12% and a permeability of 0.6 mD. • The Abu Madi sandstones represent the largest gas-bearing reservoirs in Nile Delta Basin. • The Abu Madi Formation is divided into two depositional sequences. • The favorable gas intervals correspond the sandstones of the LST rather than the HST or the TST. • The massive sandstone-rock type is the best reservoir type by displaying the highest interparticle porosity and permeability. [ABSTRACT FROM AUTHOR]

Natural stone has been a popular and reliable building material throughout history appearing in many historic monuments and in more recent buildings. Research into the intrinsic properties of specific stones is important because it gives us a greater understanding of the factors that limit and act on them. This can help prevent serious problems from occurring in our buildings bringing both esthetic benefits and financial savings. To this end, the main objective of this research has been to study the influence of the fabric and the mineral composition of two types of sandstone on their durability. The first is a red continental sandstone from the Buntsandstein Age called “Molinaza Roja”, which is quarried in Montoro (Cordoba). The second is quarried in Ronda (Malaga) and is sold under the trade name of “Arenisca Ronda”. It is a light pink-whitish calcarenite deposited during the Late Tortonian to Late Messinian. We characterized their petrological and petrophysical properties by studying their rock fabrics, porous systems and mechanical properties. In order to obtain a complete vision of the behavior of their rock fabrics, we also carried out two decay tests, the salt crystallization and the freeze–thaw tests. We then measured the effects on the textures of the altered samples during and after the decay tests and we evaluated the changes in the porous system. By comparing the results between intact and altered samples, we found that Arenisca Ronda is less durable because it has a high quantity of expandable clays (smectites) and a high percentage of pores in the 0.1–1 μm range, in which the pressure produced by salt crystallization is strongest. In Molinaza Roja the decay agents caused significant sanding due to loss of cohesion between the clasts, especially during the salt crystallization test. In both stones, the anisotropies (oriented textures) have an important role in their hydric and dynamic behavior and also affect their mechanical properties (especially in the compression resistance). No changes in color were detected. [ABSTRACT FROM AUTHOR]

To assess the long-term safety of a geological carbon dioxide storage site, the confining properties of the rocks sealing an underground reservoir (caprocks) and their evolution in the presence of CO2 must be characterized. The present study consists in the measurement of the transport parameters of dissolved CO2 through low permeability carbonate-rich caprocks. The properties of interest are the effective permeability and the diffusion coefficients of carbon dioxide dissolution products in water. The impact of carbon dioxide has been evaluated when altering rock samples by diffusion of a CO2-saturated brine under reservoir thermodynamic conditions, and by comparison of the pre- and post-alteration measured values. Permeability was measured by a gas-tracing method and, to study diffusion, radioactive isotopes of carbon (14C) and hydrogen (³H) were used. Despite a porosity increase observed for all the studied samples, the low values of transport parameters, measured initially, were also measured after alteration, showing a non-catastrophic alteration of the material. [ABSTRACT FROM AUTHOR]

Abstract: The technical quality of two compositionally different groups of solid bricks fired between 800 and 1000°C was evaluated. Five weight percentage of fly ash was added to both groups and they were compared with similar bricks with no added fly ash. The textures of the bricks with fly ash were very similar to the textures of those without it, except that the samples with the additive contained spherical fly ash particles with diameters ranging from 0.1 to 10μm. These particles led to a reduction in the density of the bricks and a substantial improvement in their durability, with less decay being caused by salt crystallization in the pores. This is because fly ash causes a reduction in the number of micropores, the pores that make porous materials most vulnerable to salt-induced decay. Use of this additive could have practical implications as a means of recycling and for achieving cost savings in brick production. [Copyright &y& Elsevier]

• Petrophysical attributes of the Alamein dolomite reservoir are characterized. • Machine learning approach by Random Forest Regression delivered better permeability prediction than conventional methods. • A new petrofacies zonation scheme is proposed in the heterogenous reservoir. • Inferences are drawn on oil production and optimum drilling-completion strategy. Capturing the petrophysical heterogeneities within a reservoir has a critical influence on reservoir deliverability as well as field development programs. In this study, we report a comprehensive petrophysical evaluation of the oil-producing Aptian Alamein dolomite reservoir from the North Razzak field, Western Desert of Egypt. Integration of wireline logs and routine core analysis indicates that the Alamein reservoir has an extremely wide range of porosity (1–23%) and permeability (0.01–7000 mD), contributed by the early diagenetic dolomitization history and complex distribution of vugs. Petrophysical assessment by reservoir quality index (RQI) and flow zone indicator (FZI) infers that the megaporous rock types offer very good to excellent reservoir qualities and macroporosity dominated intervals are of fair to good quality. Further, we developed a permeability prediction model in this challenging carbonate rock based on Random Forest (RF) regression, and tested its efficacy and generalizability by well-defined performance metrics. The RF-based algorithm provided a more confident permeability prediction (R2 = 0.937) compared to conventional methods. Based on the petrophysical attributes; six distinct petrofacies (PF) associations are identified. PF-1, PF-3, and PF-5 provide excellent reservoir qualities with superlative storage capacity and hydraulic flow potential contributed by connected vugs, while the microporosity-dominated impervious PF-2 and PF-4 intervals act as intra-reservoir permeability barriers. We suggest that the higher initial oil production rate was mainly contributed by the larger connected pores and vuggy spaces. As reservoir pressure drops, hydrocarbon flows restrict to the smaller pores causing accelerated production weakening. Based on this comprehensive analysis, a suitable drilling and completion strategy is recommended for the future reservoir development program. [ABSTRACT FROM AUTHOR]

Reservoir petrophysical characterization involving permeability estimation in the laboratory using core samples is time-consuming and that too accords limited coverage of the sub-surface reservoir. Machine learning (ML) algorithms have been utilized to overcome such difficulties, which offers better and more accurate prediction models. This work integrates core data and ML approached and reports a comprehensive petrophysical evaluation of the Cenomanian Bahariya and Albian Kharita reservoirs from the Badr El Din-1 field, Western Desert of Egypt. Three distinct reservoir rock types are identified from the detailed petrographic investigation: i) glauconitic sandstones (RRT1) and ii) subfeldspathic quartz arenites (RRT2) within Bahariya Formation and iii) quartz arenites (RRT3) within Kharita Formation. Reservoir quality index (RQI), flow zone indicator (FZI), and hydraulic flow units (HFU) are interpreted from the routine core analysis, which infers that the RRT1 has poor permeability (K H < 1 mD) and impervious (RQI < 0.25 μm, FZI <1 μm). Transgressive shoreface deposits of RRT2 display a wide range of porosity (5.9–18.5%) and permeability (0.82–76 mD) distribution and offer poor to fair reservoir qualities (1 μm < FZI < 5 μm) with moderate to high permeability anisotropy. Well sorted medium grained quartz arenites (RRT3) were deposited in a braided fluvial channel environment and contributed to the excellent reservoir quality with an average K H of 468 mD, FZI > 5 μm, and lesser permeability anisotropy. Finally, two-hybrid ML-based algorithms such as particle swarm optimization (PSO) trained neural network (NN) and least squares support vector machines (LS-SVM) have been employed to estimate the permeability. Based on the statistical performance metrics, we conclude that both the ML algorithms performed exceptionally well as compared to the conventional method, which is attributed to their enhanced competence to model the connectivity within the pore microstructures of the reservoir rocks with proper recognition of the pattern in the training data. Our results indicate that amongst the PSO-NN and LS-SVM algorithms, the latter is more superior since it is comparatively more accurate and reliable in permeability prediction. • Petrophysical attributes of the Cenomanian Bahariya (transgressive shoreface) and Albian Kharita (fluvial) reservoirs are characterized. • Kharita Formation has excellent reservoir qualities, while the Bahariya reservoir has poor to fair quality. • Two hybrid ML-based algorithms have been employed to estimate the horizontal and vertical permeabilities. • Least squares support vector machines (LS-SVM) provided more accurate prediction than particle swarm optimization trained neural network (PSO-NN). [ABSTRACT FROM AUTHOR]

An integrated knowledge of the sedimentological data, petrophysical and geomechanical characteristics significantly enhances the understanding of the reservoir properties, leading to a reliable subsurface modeling. This work presents a comprehensive reservoir assessment of the prolific Triassic Argilo-Gréseux Inférieur (TAGI) sandstones of the Hassi Berkine South (HBNS) field, Southeastern Algeria. The Lower Triassic producer appears to be laid down on the Late Devonian erosional surface (Hercynian unconformity) in a fluvial depositional system. Based on the sedimentary structures, a fluvial depositional environment is deciphered from cores. Lateral and vertical disposition of the channel and floodplain deposits from regional well log correlation infers a shift of depositional regime from braided in the SW to meandering in the NE direction. Two distinct reservoir rock types (RRT) are interpreted from core-based petrophysical assessment. RRT1 is composed of macro-megaporous medium to very coarse grained amalgamated channel sandstones and yields the best reservoir attributes, while the mesoporous fine grained RRT2 translates to impervious to poor reservoir quality. RRT1 channel sands are found to be laterally continuous, while the fine grained crevasse splay sands corresponding to RRT2 are laterally discontinuous, thus making them difficult to correlate field wide. Rock-mechanical property-based in-situ stress estimates suggested a normal to strike-slip transitional (S v ≥ S HMax > S hmin) stress state in the TAGI Formation. Direct measurements indicate that the TAGI reservoir had an initial pore pressure gradient of 11.08 MPa/km and is presently depleted by 2.1–2.5 MPa. A stable depletion stress path value of 0.57 is inferred considering a pore pressure-minimum horizontal stress coupling. At the present-day depletion rate, normal faulting is unlikely to have happened at the TAGI reservoir level and it can be depleted by another 25 MPa before inducing any production-induced reservoir instabilities. • Sedimentary structures interpreted from the cores reveal a fluvial depositional environment responsible for TAGI Formation. • Petrophysical rock typing infers that the medium to coarse grained, laterally extensive, amalgamated channel sandstones (RRT1) yield the best reservoir attributes. • TAGI has a normal to strike-slip transitional (S v ≥ S HMax > S hmin) stress state. • Reservoir stress path and available depletion window are implied to avoid production-induced normal faulting. [ABSTRACT FROM AUTHOR]

As a major supplement to conventional fossil fuels, unconventional oil and gas resources have received significant attention across the globe. However, significant challenges need to be overcome in order to economically develop these resources, and new technologies based on a fundamental understanding of flow and transport processes in unconventional reservoirs are the key. This special issue collects a series of recent studies focused on the application of novel technologies and theories in unconventional reservoirs, covering the fields of petrophysical characterization, hydraulic fracturing, fluid transport physics, enhanced oil recovery, and geothermal energy. [ABSTRACT FROM AUTHOR]