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Cenozoic reservoirs of northern Rovuma Basin, Tanzania, have not yet been characterized in detail. Combined well log patterns and fracture indicators have not been presented before. This work used petrophysical analysis of density, neutron, gamma ray (GR), resistivity and sonic well logs to characterize reservoir zones at the study area. Twelve reservoir zones (A–L) have been identified based on lithological properties and resistivity anomalies. The presence of hydrocarbons in these zones is concluded based on acoustic parameters involving acoustic impedance and ${V_p}$ V p / ${V_s}$ V s ratio, and ∆TC and neutron porosity crossplots. Fractured sedimentary fills in different stratigraphic levels were assessed based on resistivity-logs crossplots. Results show that eleven zones (A–F and H–L) are gas-filled and zone G is devoid of hydrocarbon. We have shown that, in areas with resistivity anomaly, all GR-resistivity combined patterns may be used to indicate hydrocarbon bearing layers except when there is a co-occurrence of funnel-shaped pattern for both logs. Distribution of fractures and hydrocarbons suggest the existence of compartmentalized reservoirs. These reservoirs have been discussed based on a geoseismic model created to support our arguments. Our technique has allowed easier identification of hydrocarbon bearing zones through well Rx. This technique may be applied in other sedimentary basins. [ABSTRACT FROM AUTHOR]

This study demonstrates an integrated approach using a seismic-coloured inversion to derive the hydrocarbon potential of a field in the Upper Assam basin. The well-log analysis indicated the presence of hydrocarbon in the form of gas, oil, and water in sandstones with thin streaks of limestone and shale layers. The Acoustic Impedance (AI) model was generated from post-stack seismic data using a coloured inversion. Shale volume (Vshale), density, porosity and water saturation are the petrophysical parameters spatially populated using a multilayered feed-forward neural network on the inversion-based AI model. The estimated range of model-derived parameters varies as Velocity: 2136–5034 m/s, Vshale: 0–48%, Density: 2.14–2.72 gm/cc, Porosity: 6–29%, Water saturation: 9–28%, and demonstrates a reasonable correlation to well-log data. Seismic attribute for thin-fault likelihood was used to interpret the major faults. From the combined analysis based on interpreted faults and modelled parameters, the northwestern part of the study area displays a thick hydrocarbon-bearing zone (due to increasing thickness and reservoir quality). This interpretation is based on the consideration that faults are open. Thus, assuming continuity in the sequence, this northwestern region can be considered as one of the promising candidates for further exploration. [ABSTRACT FROM AUTHOR]

This study investigates the GABO field in the onshore Niger Delta Basin using well logs and core samples, with a focus on rock type distribution, reservoir continuity, and petrophysical properties to enhance hydrocarbon exploration accuracy. The research involved detailed analysis of core descriptions and images from GABO-20, along with petrophysical data from wells GABO-4, GABO-12, GABO-13, GABO-20, and GABO-51, aiming to identify rock types, evaluate reservoir quality, and determine the spatial distribution of petrophysical properties. The methodology included rigorous well log quality checks, data correlation between wells, petrophysical property evaluation, and lithofacies description. The analysis revealed thirty-five hydrocarbon-bearing zones, with GABO-20 showing average shale fraction values between 0.111 and 0.335, total porosity ranging from 0.242 to 0.329, and hydrocarbon saturation from 0.667 to 0.923, indicating substantial porosity and hydrocarbon saturation conducive to extraction. Well correlations demonstrated excellent sand-shale continuity within the reservoir intervals. Lithofacies analysis of the GABO-20 core identified eight distinct facies, including shale poles, liquid-rich shales, and sandstone poles, revealing a complex distribution of reservoir qualities with significant variations in potential. Cores 1 and 2 exhibited favourable conditions for hydrocarbon production, while Core 3 showed lower reservoir quality due to increased clay content. The depositional settings of the GABO field, particularly in the lower delta plain and delta front zones, showed well-developed reservoir bodies with moderate potential in the tidal zone and little potential in the shaly prodelta environment. This distribution highlights the complexity of the deltaic system and its implications for reservoir modeling and utilization. Reservoir zones associated with High-Quality Reservoir Facies exhibited strong petrophysical properties, suggesting excellent hydrocarbon production potential. The study underscores the importance of detailed reservoir characterization to optimize recovery strategies, offering valuable insights into the distribution and quality of reservoir sands, reducing subsurface uncertainty, and emphasizing the integration of facies and petrophysical approaches for a better understanding of reservoir characteristics in the GABO field.

Hydrocarbon reservoir characterization using well log in part of Niger Delta, Nigeria was done in order to examine the potentiality and productivity of the reservoir. A suite of well log data consisting of gamma ray, density, resistivity and neutron logs obtained from two wells within the area of study were used for this research. Gamma ray log was used for lithology identification and differentiation, resistivity log was used to identify the type of fluid present in the reservoir, density log was used to detect gas bearing zones in the reservoir while neutron log was used to distinguish gas from oil in sandstone and shale reservoirs. The results of this study showed sand bodies were delineated and correlated across the wells and were inferred as potential hydrocarbon reservoirs. The result also showed that there is an increase in both porosity and permeability, evaluated petrophysical parameters showed that porosity values range between 0.0391 - 0.3019, water saturation values range from 0.1660 - 1.6740 while hydrocarbon saturation values range from 0.0013 - 0.7296 and net to gross values range from 0.5332 - 0.9674. [ABSTRACT FROM AUTHOR]

Petrophysical evaluation and hydrocarbon prospectivity of Osaka Field in Niger Delta Nigeria was carried out with the aim of identifying the reservoir and estimating the hydrocarbon-bearing potentials of the reservoirs. Composite suite of well logs comprising gamma ray, resistivity, neutron porosity, density porosity and sonic logs were acquired from an oil producing company. Four wells, Osaka well 001, well 002, well 003 and well 004 were used for the exercise. The logs were uploaded into the Petrel Workflow software. Three reservoirs R1, R2 and R3 were correlated and petrophysical parameters (porosity, permeability, water saturation, irreducible water saturation, and hydrocarbon saturation and formation factors) computed. Hydrocarbon discrimination was done using the overlay of the neutron and the density porosity logs. The petrophysical analysis result showed that the water saturation varies from 15% to 46% in well 1, 38% to 46% in well 2, 40% to 65% in well 3 and 26% to 40% in well 4. The irreducible water saturation also varies from 4% to 8% in well 1, 6% to 8% on well 2, 5% to 7% in well 3, 5% to 7% in well 4. Based on the results obtained from the hydrocarbon saturation which vary from 53% to 84% in well 1, 54% to 62% in well 2, 40 to 69% in well 3 and 60% to 74% in well 4. It is concluded from the study that reservoir rocks in the studied wells in Osaka field generally are prospective and could be exploited for exploration purposes. [ABSTRACT FROM AUTHOR]

This study analyzed “Shula field” offshore Niger Delta basin for it hydrocarbon bearing capacity. Well logs and seismic data were used for the analysis. Well logs consisting of gamma ray, resistivity, neutron and density logs for five different wells were used. Gamma ray logs aided lithological identification, resistivity logs were used to delineate hydrocarbon bearing zones while a combination of neutron and density logs aided in distinguishing oil and gas zones. Three hydrocarbon bearing sands (reservoirs) of varying thickness designated as RES-AA, RES-BB and RES-CC were identified. Well log correlation of the five wells revealed lateral continuity of the sand units thinning out in northwestern direction of the study field. The range values of gross thickness (GT), net-to-gross (NTG), volume of shale (VSH), effective porosity (ΦEff), permeability (K), hydrocarbon saturation (Sh) and water saturation (SW) for RES-AA reservoir are 51-74ft, 0.88-98%, 0.10- 11%, 24-28%, 174-734mD, 8-80%, and 20-92% respectively. RES-BB reservoir range values of (GT), (NTG), (VSH), (ΦEff), (K), (Sh) and (SW) are 47-65ft, 83-98%, 8-14%, 24-32%, 234-1880mD, 4-78%, and 22-96% respectively while the RES-CC reservoir range values of (GT), (NTG), (VSH), (ΦEff), (K), (Sh) and (SW) are 121- 191ft, 82-96%, 8-11%, 23-31%, 125-1352mD, 9-88% and 12-91% respectively. Sixteen faults were identified and interpreted comprising of nine synthetic and seven antithetic faults. The time and depth structural maps show the subsurface structural geometry and possible hydrocarbon migration and trapping potential. The probable structure trapping hydrocarbon in the study field is anticlinal structure and four-way closure. The volumetric calculation revealed that reservoir RES-AA has 951 × 106 bbl, reservoir RES-BB has 1058 × 106 bbl and reservoir RES-CC has 1688 × 106 bbl of oil originally in place (OIIP). Generally, the petrophysical results and the volumetric calculation for the field confirm an economically viable investment potential except for reservoir RES-AA, wellbore ZY-005 with 8% Sh, reservoir RES-BB, wellbore ZY-003 and ZY-005 with 4% Sh, and 7% Sh respectively and reservoir RES-CC, wellbore ZY-005 with 9% Sh. Therefore, these four reservoir units may be screen out during production to reduce the rate of water cut thereby increasing the producing life of the field.

This archaeometric study aims at characterizing the archaeological finds belonging to the lithic industry from La Calvera rock shelter (Camaleño, Cantabria) and at hypothesizing the possible provenance of each material. The site, located in the mountainous area of Picos de Europa National Park (more than 1000 m a.s.l.) close to the megalithic complex of Peña Oviedo, is characterized by the presence of hearths and charcoal remains, ancient pottery, and a rich lithic assemblage composed of siliceous rocks dating back to >8000 BP and linked to the first Holocene occupations of the Cantabrian Mountains. For the study of the rock shelter's lithic assemblage, a multi-analytical approach was used: SEM-EDS and XRD analyses were performed to define the microtextural characteristics of samples and to identify the amorphous/crystalline phases; physical and mechanical tests were conducted to define the petrophysical properties (density, porosity, imbibition and saturation indexes, mechanical strength) of the samples. Preliminary data of chemical compositions, obtained by portable XRF, are also presented. The results show that the different siliceous materials (quartzite, cherts, hyaline quartz) can be distinguished through the basic analytical techniques used here. In addition, most of the archaeological samples have mineralogical and petrographic features similar to the natural samples coming from nearby outcrops, corroborating the hypothesis of a local material supply. The presence of local sources of useful raw materials could have favoured the site's occupation. Finally, the diverse compositional and textural feature of the analysed materials result in different mechanical properties (porosity, density, hardness, workability), so they likely had different uses and technical functions. [ABSTRACT FROM AUTHOR]

The study aims to implement a high-resolution Extended Elastic Impedance (EEI) inversion to estimate the petrophysical properties (e.g., porosity, saturation and volume of shale) from seismic and well log data. The inversion resolves the pitfall of basic EEI inversion in inverting below-tuning seismic data. The resolution, dimensionality and absolute value of basic EEI inversion are improved by employing stochastic perturbation constrained by integrated energy spectra attribute in a Bayesian Markov Chain Monte Carlo framework. A general regression neural network (GRNN) is trained to learn and memorize the relationship between the stochastically perturbed EEI and the associated well petrophysical log data. The trained GRNN is then used to predict the petrophysical properties of any given stochastic processed EEI. The proposed inversion was successfully conducted to invert the volume of shale, porosity and water saturation of a 4.0 m thick gas sand reservoir in Sarawak Basin, Malaysia. The three petrophysical geobodies were successfully built using the discovery wells cut-off values, showing that the inverted petrophysical properties satisfactorily reconstruct the well petrophysical logs with sufficient resolution and an accurate absolute value at the well site and are laterally conformable with seismic data. Inversion provides reliable petrophysical properties prediction that potentially helps further reservoir development for the study field. [ABSTRACT FROM AUTHOR]

The study reports the approach of interrelating geotechnical and petrophysical parameters to develop near-surface lithology clusters in a sedimentary terrain. Field-based and laboratory-based geophysical, geotechnical, and petrophysical measurements were carried out with a view to finding correlations among related parameters, grouping the parameters into depth clusters, and determining trend correlations between field-acquired and laboratory-obtained parameters. Four agglomerate hierarchical cluster signatures were identified at depth 0–30 cm, three at 30–60 cm, and five at 0–90 cm. Principal component 1 retained 74% of data variation and differentiated the petrophysical parameters according to Poisson’s ratio (v) and velocity ratio (Vp/Vs). Principal component 2 explained another 14% of variability in the original responses and separated parameters based on elastic modulus (E) and clay fraction (C). Degree of correlation of Vp/Vs with porosity (Φ), sand fraction (S), C, unconfined compressive strength (U), and California bearing ratio (R) followed order Φ > S > C, and U > R. Trend correlation of shear velocity at 1 m showed good agreement (R2 = 0.992) between field and laboratory data with an amplification factor of 4.13 separating the corresponding values. Lithology determined from soil analysis agreed with that inferred from measured electrical resistivity while geotechnical, petrophysical, and geophysical spatial analysis supported site lithology configuration patterns. Thus, multivariate association of geotechnical and petrophysical parameters exhibited potentials for rapid and exploratory near-surface lithology mapping even at a regional scale. [ABSTRACT FROM AUTHOR]

The study aims to implement a high-resolution Extended Elastic Impedance (EEI) inversion to estimate the petrophysical properties (e.g., porosity, saturation and volume of shale) from seismic and well log data. The inversion resolves the pitfall of basic EEI inversion in inverting below-tuning seismic data. The resolution, dimensionality and absolute value of basic EEI inversion are improved by employing stochastic perturbation constrained by integrated energy spectra attribute in a Bayesian Markov Chain Monte Carlo framework. A general regression neural network (GRNN) is trained to learn and memorize the relationship between the stochastically perturbed EEI and the associated well petrophysical log data. The trained GRNN is then used to predict the petrophysical properties of any given stochastic processed EEI. The proposed inversion was successfully conducted to invert the volume of shale, porosity and water saturation of a 4.0 m thick gas sand reservoir in Sarawak Basin, Malaysia. The three petrophysical geobodies were successfully built using the discovery wells cut-off values, showing that the inverted petrophysical properties satisfactorily reconstruct the well petrophysical logs with sufficient resolution and an accurate absolute value at the well site and are laterally conformable with seismic data. Inversion provides reliable petrophysical properties prediction that potentially helps further reservoir development for the study field.

Abstract Stimulation of the sandstone reservoir requires a mixture of acids such as mud acid, which assist in enlarging the microscopic paths by dissolving the siliceous fines or clays near the well-bore region. As a result, the formation permeability and porosity can be enhanced. In deeper wells, the temperature exceeds 200 °F, at these temperature ranges, problems can arise. For example, the use of mud acid mixtures can lead to issues like precipitations, corrosion, early consumption of acids, leading to lesser acid efficiency. In this study, the core flooding apparatus was used for acidizing experiments, designed to dissolve minerals and to analyze the changes in petrophysical parameters such as porosity, permeability, and mineralogy. Conventional and tight sandstone core samples were acidized using different chelating acids such as Hydroxyethylethylenediaminetriacetic acid (HEDTA), Ethylenediaminetetraacetic acid (EDTA) and Glutamic acid (GLDA) at high-temperature conditions. Analytical studies (mineral mass, pore size distribution, topology, grain size distribution, and density distribution were conducted using Tescan Integrated Mineral Analysis (TIMA). The obtained results showed that chelating agent HEDTA created more pore spaces in the core samples and is effective in dissolving positive ions. Also, the permeability was observed to be doubled by its application which could be effective in alteration of pore topology of the sandstone cores.

The reservoir characteristics and hydraulic flow properties of the Mount Messenger Formation, New Zealand, have been investigated to identify the reservoir quality and factors affecting it. In this study, the porosity–permeability relationship is a significant factor for discriminating the reservoir rock into four groups. Petrophysically, group I has the best storage capacity (max. 30.5%) and the highest permeability (max. 1230 mD), and values of RQI, FZI, RPI, and r35 indicate good to very good reservoir quality, while group IV comprises very low permeability (max. 0.69 mD), and the RQI, FZI, RPI, and r35 values represent impervious reservoir quality, but still, it consists of good porosity values (max. 20.6%). The petrophysical parameters from group II indicate poor to good reservoir quality, whereas group III represents poor reservoir quality. The petrographical studies show the occurrence of abundant intergranular primary porosity only in groups I and II and isolated pores in groups III and IV. Compaction and the presence of the authigenic clay minerals are the dominant diagenetic features destroying the reservoir quality of groups III and IV. The samples of group I are devoid of clay and not susceptible to compaction; this explains that it exhibits potential reservoir properties, while group II has a minor effect of diagenesis. This study reveals that the deep-water turbidite Mount Messenger Formation is a promising reservoir with excellent porosity values and consists of several flow units, which can be treated as an analogous of turbidite deposits in other petroleum basins. [ABSTRACT FROM AUTHOR]

The frequency-dependent amplitude-versus-offset (FAVO) method has become a practical method for fluid detection in sand reservoirs. At present, most FAVO inversions are based on the assumption that reservoirs are isotropy, but the application effect is not satisfactory for fractured reservoirs. Hence, we analyse the frequency variation characteristics of anisotropy parameters in tight sandstone reservoirs based on a new petrophysical model, and propose a stepwise anisotropic FAVO inversion method to extract frequency-dependent attributes from prestack seismic field data. First, we combine the improved Brie's law with the fine-fracture model to analyse frequency-dependent characteristics of velocities and Thomsen anisotropy parameters at different gas saturations and fracture densities. Then, we derive an anisotropic FAVO inversion algorithm based on Rüger's approximation formula and propose a stepwise anisotropic FAVO inversion method to obtain the dispersions of anisotropy parameters. Finally, we propose a method that combines the inversion spectral decomposition with the stepwise anisotropy FAVO inversion and apply it to tight sand reservoirs in the Xinchang area. We use P-wave velocity dispersion and anisotropy parameter ε dispersion to optimise favourable areas. Numerical analysis results show that velocity dispersion of the P-wave is sensitive to fracture density, which can be used for fracture prediction in fractured reservoirs. In contrast, anisotropic parameter dispersion is sensitive to gas saturation and can be used for fluid detection. The seismic data inversion results show that velocity dispersion of the P-wave and anisotropic parameter dispersion are sensitive to fractured reservoirs in the second member of Xujiahe Group, which is consistent with logging interpretation results. [ABSTRACT FROM AUTHOR]

Abstract Properties of rock, such as effective porosity, permeability and pore size distribution (PSD), are generally referred to as petrophysical properties. These properties are among the most significant for reservoir evaluation. Acid stimulation treatments are usually used in sandstones to mitigate the impact of formation damage, with the aim of restoring or enhancing the natural matrix permeability and consequently boosting the well productivity. Hydrochloric acid (HCl) is commonly used in the preflush stage to remove calcium and other metal ions, preventing the development of calcium fluoride (CaF2) and other silicate precipitates that could block the pore throats, while an acid mixture (HF–HCl combination) is usually preferred as the main stimulation fluid for the removal of quartz and remaining metal ions. However, sometimes the application of these acids can lead to other problems, including fast reactions, corrosion of pipes, environmental hazards, precipitation reactions and formation damage due to the incompatibility of HCl with clay minerals, so chelating agents have been proposed as an alternative for matrix stimulation fluids. In this study, three different chelating agents, ethylenediaminetetraacetic acid (EDTA), N-(2-hydroxyethyl) ethylenediamine-N,N′,N′-triacetic acid (HEDTA) and N-acetyl-l-glutamic acid (GLDA), have been used to stimulate Berea sandstone, Colton tight sandstone and Guelph dolomite samples. Core flood experiments were conducted on 1.5 × 3 (in2) core plugs, at a temperature below 180 °F. A slow injection rate of (1–0.5 cc/min) was chosen for the treatment fluid, promoting the dissolution of ions by increasing the contact time between the fluid and the rock. Furthermore, nuclear magnetic resonance, wettability and micro-computed tomography (CT scan) analyses were employed to evaluate the effect of the acid treatment on formation properties such as porosity, PSD, pore topology, wettability and pore structure. After exposing the samples to HEDTA, large wormholes were detected in their pore network, demonstrating that HEDTA has the highest potential to create new pore spaces when compared to GLDA and EDTA when reacted with both types of samples.

Three dimensional (3D) seismic data, and a suite of four geophysical well logs from four wells located on the Lee field, Niger Delta were analyzed using Petrel software for the aim of reservoir characterization and volumetric analysis of the field. The objectives among others include identification and delineation of the reservoirs and estimating the petrophysical parameters from the well logs available, generating time and depth structure maps of horizons from the seismic section, and a volumetric analysis in order to estimate hydrocarbon in place. The method adopted involves petrophysical analysis, structural analysis, static modelling, and volumetric analysis. Detailed petrophysical analysis revealed three reservoirs. Average Reservoir parameters such as effective porosity (0.17), gross thickness (86 m), hydrocarbon saturation (0.42), permeability (1215 mD) and net-to-gross (0.79) were derived from petrophysical analysis. The three reservoirs were classified using average results of petrophysical parameters. And based on these results, Reservoir 1 is the most prolific while Reservoir 3 is the least prolific within Lee field. Fault and Horizon interpretations were done using Petrel software which culminated in delivery of 3D structural map of the reservoirs. Structural, stratigraphic and Petrophysical models were developed and then integrated to produce a high resolution static model for Reservoir 1. The hydrocarbon in place shows that reservoir 1 is of appreciable thickness and areal extent. The volume of hydrocarbon originally in place was estimated to be 367,180,095.08 barrels of oil. Keywords: volumetric, petrophysical, fault, saturation, net-to-gross, permeability, horizon

Abstract Hydrocarbon play assessment of any hydrocarbon reservoir unit depends on the porosity, permeability, hydrocarbon saturation and water saturation of petrophysical model distributions and seismic reflections of reservoir rocks. The objective of the study is to resolve the ambiguities that are associated with hydrocarbon play assessment of an X-field in the Niger Delta basin. This was achieved through the use of pre-conditioned attributes, fault delineating seismic attributes such as coherence, variance and quantitative definition of the reservoir units of petrophysical model distributions, through the adoption of an integrated methodology of 3D seismic and well log data. A quick look examination of the well log signatures revealed numerous reservoir sand units, but only three hydrocarbon-bearing reservoir sands were of interest to us (RS1, RS2 and RS3). From the quantitative interpretation of well logs, the three identified reservoir sands were evaluated in terms of porosity, permeability, hydrocarbon saturation, shale volume, movable hydrocarbon index and water saturation. Effective porosity values of 24.56, 23.01 and 24.00% were obtained for Well 1, Well 2 and Well 4, respectively. This supports the known or already established porosity range of Agbada Formation of Niger Delta with range 28–32%. The hydrocarbon saturation for RS2 is 68.51% for Well 4, for RS3 72.49% for Well 3 and for RS2 74.16% and for RS3 77.34% for Well 2. RS2 of 79.51% and RS3 of 80.99% for Well 1 were obtained. This shows how prolific the reservoir sand units are with hydrocarbon accumulation tendencies. Structural analysis revealed a highly faulted system that depicts a typical tectonic setting of the Niger Delta basin, and the computed attributes like coherence, and variance shows an optimum visualization of the faulting system. This implies that the trapping mechanism of the field is of both anticlinal and fault-assisted closure and also the viability of the reservoir units is high from the computed petrophysical parameters.

Stimulation of the sandstone reservoir requires a mixture of acids such as mud acid, which assist in enlarging the microscopic paths by dissolving the siliceous fines or clays near the well-bore region. As a result, the formation permeability and porosity can be enhanced. In deeper wells, the temperature exceeds 200 °F, at these temperature ranges, problems can arise. For example, the use of mud acid mixtures can lead to issues like precipitations, corrosion, early consumption of acids, leading to lesser acid efficiency. In this study, the core flooding apparatus was used for acidizing experiments, designed to dissolve minerals and to analyze the changes in petrophysical parameters such as porosity, permeability, and mineralogy. Conventional and tight sandstone core samples were acidized using different chelating acids such as Hydroxyethylethylenediaminetriacetic acid (HEDTA), Ethylenediaminetetraacetic acid (EDTA) and Glutamic acid (GLDA) at high-temperature conditions. Analytical studies (mineral mass, pore size distribution, topology, grain size distribution, and density distribution were conducted using Tescan Integrated Mineral Analysis (TIMA). The obtained results showed that chelating agent HEDTA created more pore spaces in the core samples and is effective in dissolving positive ions. Also, the permeability was observed to be doubled by its application which could be effective in alteration of pore topology of the sandstone cores. [ABSTRACT FROM AUTHOR]

Sand failure and production occurs when the formation stress exceeds the strength of the formation, which is derived majorly from the natural material that cements the sand grain and cohesive forces. This study investigates the effects of scale inhibitor, biocide and corrosion inhibitor on the geomechanical strength of reservoir rocks (carbonate and sandstone). Integration of geomechanical, petrophysical and analytical techniques is used to establish the failure effects of the interaction of these chemicals on the geomechanical strength of reservoir rocks and failure mechanisms resulting from such interaction. The results confirm that chemical adsorption, dissolution, precipitation and ionic substitution reactions took place between the oilfield chemicals and the formation rocks leading to weakening of the reservoir grain fabrics and reduction in unconfined compressive strength which in turn causes sand failure. [ABSTRACT FROM AUTHOR]

Abstract A reservoir characterization study, using petrophysical and petrographic analyses, has been made on the Paleocene Farewell Formation in the Taranaki Basin, New Zealand, based on five selected wells. Farewell Formation is largely a sandstone formation belonging to the Kapuni Group. The integrated study has shown that Farewell Formation is a good promising reservoir with average effective porosity of 17.7% and permeability of 415 mD. The petrographic study indicates the occurrence of abundant intergranular and secondary pores. It also proved that the Farewell Formation has been affected by several diagenetic features. Compaction, cementation and clay mineral authigenesis are the most common. Quartz and feldspar overgrowths have been recorded in many samples, and secondary porosity due to dissolution is also observed. In general, good reservoir quality features are dominant in the Farewell Formation and diagenesis has little effect on the reservoir quality. These findings are supported by well log interpretation results, which confirm good sand and net pay zones are available with very low average water saturation (24.9%).

Three dimensional (3D) seismic data, and a suite of four geophysical well logs from four wells located on the Lee field, Niger Delta were analyzed using Petrel software for the aim of reservoir characterization and volumetric analysis of the field. The objectives among others include identification and delineation of the reservoirs and estimating the petrophysical parameters from the well logs available, generating time and depth structure maps of horizons from the seismic section, and a volumetric analysis in order to estimate hydrocarbon in place. The method adopted involves petrophysical analysis, structural analysis, static modelling, and volumetric analysis. Detailed petrophysical analysis revealed three reservoirs. Average Reservoir parameters such as effective porosity (0.17), gross thickness (86 m), hydrocarbon saturation (0.42), permeability (1215 mD) and net-to-gross (0.79) were derived from petrophysical analysis. The three reservoirs were classified using average results of petrophysical parameters. And based on these results, Reservoir 1 is the most prolific while Reservoir 3 is the least prolific within Lee field. Fault and Horizon interpretations were done using Petrel software which culminated in delivery of 3D structural map of the reservoirs. Structural, stratigraphic and Petrophysical models were developed and then integrated to produce a high resolution static model for Reservoir 1. The hydrocarbon in place shows that reservoir 1 is of appreciable thickness and areal extent. The volume of hydrocarbon originally in place was estimated to be 367,180,095.08 barrels of oil. [ABSTRACT FROM AUTHOR]

Properties of rock, such as effective porosity, permeability and pore size distribution (PSD), are generally referred to as petrophysical properties. These properties are among the most significant for reservoir evaluation. Acid stimulation treatments are usually used in sandstones to mitigate the impact of formation damage, with the aim of restoring or enhancing the natural matrix permeability and consequently boosting the well productivity. Hydrochloric acid (HCl) is commonly used in the preflush stage to remove calcium and other metal ions, preventing the development of calcium fluoride (CaF2) and other silicate precipitates that could block the pore throats, while an acid mixture (HF–HCl combination) is usually preferred as the main stimulation fluid for the removal of quartz and remaining metal ions. However, sometimes the application of these acids can lead to other problems, including fast reactions, corrosion of pipes, environmental hazards, precipitation reactions and formation damage due to the incompatibility of HCl with clay minerals, so chelating agents have been proposed as an alternative for matrix stimulation fluids. In this study, three different chelating agents, ethylenediaminetetraacetic acid (EDTA), N-(2-hydroxyethyl) ethylenediamine-N,N′,N′-triacetic acid (HEDTA) and N-acetyl-l-glutamic acid (GLDA), have been used to stimulate Berea sandstone, Colton tight sandstone and Guelph dolomite samples. Core flood experiments were conducted on 1.5 × 3 (in2) core plugs, at a temperature below 180 °F. A slow injection rate of (1–0.5 cc/min) was chosen for the treatment fluid, promoting the dissolution of ions by increasing the contact time between the fluid and the rock. Furthermore, nuclear magnetic resonance, wettability and micro-computed tomography (CT scan) analyses were employed to evaluate the effect of the acid treatment on formation properties such as porosity, PSD, pore topology, wettability and pore structure. After exposing the samples to HEDTA, large wormholes were detected in their pore network, demonstrating that HEDTA has the highest potential to create new pore spaces when compared to GLDA and EDTA when reacted with both types of samples. [ABSTRACT FROM AUTHOR]

In the present study, the Jurassic Bir El-Maghara and Masajid Formations in North Sinai are subjected to a detailed microfacies analysis to identify the effect of the diagenetic factors on their geomechanical and petrophysical properties. The Bir El-Maghara Formation consists of mudstone microfacies, whereas the Masajid Formation consists of foraminiferal and molluscan mudstone microfacies, oolitic grainstone microfacies, mudstone microfacies, and foraminiferal-algal sparitic mudstone microfacies. These microfacies were deposited in restricted platform conditions through the entire section with some oscillations into shelf lagoon conditions in the middle parts of the sequence. The porosity and bulk density of Masajid and Bir El-Maghara Formations are strongly correlated with their petrophysical and geomechanical properties. These correlation relationships can help estimate the geomechanical properties statistically in terms of the petrophysical parameters. [ABSTRACT FROM AUTHOR]

An integrated approach was deployed to relate the petrographical and petrophysical parameters of the Chorgali Formation to assess its reservoir potential. The petrographical study of the Chorgali Formation, exposed in Khair-e-Murat Range, disclosed that the original texture and composition are affected by diagenetic events (i.e. micritization, dolomitization, microfractures, stylolitization, compaction, dissolution, neomorphism and cementation). Of these, dissolution, dolomitization and microfractures enhanced reservoir quality, while micritization, compaction, neomorphism and cementation reduced reservoir suitability. Micritization occurred in marine phreatic conditions; dolomitization existed in the marine-meteoric mixing environment; dissolution, neomorphism and cementation took place in meteoric conditions. The mechanical and chemical compaction occurred in a burial diagenetic environment. In addition, the relationship among formation resistivity factor (F), compressional wave velocity (Vp) and porosity (ɸ) was also validated for the Eocene Chorgali Formation of Meyal Oil Field, Potwar Plateau, Pakistan. There is an inverse relationship between ɸ and F, Vp, however, the relation between F and Vp is directly proportional. Such inter-relationships assist in determining and interpreting the geological processes based on petrophysical parameters (ɸ, F and Vp). F and Vp may be high due to cementation, compaction, sealed fractures and lack of deformation in carbonates. On the other hand, F and Vp may be low due to dissolution, dolomitization, vacant fractures, lack of compaction and cementation. Similarly, ɸ is enhanced by processes lowering F and Vp and reduced by processes increasing F and Vp. Hence the diagenetic processes enhancing and reducing the porosity influence the electric and elastic properties of the carbonate rocks. [ABSTRACT FROM AUTHOR]

Significantly, Snefru northern pyramid is the first successful true complete Pyramid was built in Egypt. It has suffered from different kinds of geo-environmental impact and other mechanical and dynamic actions; aspects of structural deficiency and building material decay are recorded and monitored. The scope of this pilot study is to ensure the structure stability and weathering vulnerability of the building materials of Snefru northern pyramid under different environmental, geotechnical and seismic loading conditions. It has been achieved through the following steps: (1) Evaluation of the building materials; includes the integrated petrography study, petro-physical and geo-mechanical testing (2) Estimations of relevant factors affecting these building materials (3) integrated modeling of the pyramid geo-environment conditions. The present study reveals that the Snefru pyramid is considered the only composite pyramid structure, which is composed of local Dolomitic sandstone body blocks which had been quarried from Dahshur plateau, and joining with pure hydraulic lime mortars and covered with imported casing limestone layers from Tura Formations. Stripped from its limestone casing, this pyramid reveals the reddish sandstone used to build its core. This explains its modern-day name, the red Pyramid. The detailed analytical study proved that this important monument present poor engineering properties and low safety factors for both static and seismic loading. The present study indicates the dependence of the mechanical properties on the petro-physical and the geochemical properties of the studied construction materials. Modeling the properties indicates a reliable correlation between the different parameters. Consequently a well-focused strengthening and retrofitting program is deemed necessary. [ABSTRACT FROM AUTHOR]

A joint petrophysical and structural inversion method for electromagnetic (EM) and seismic data based on the volume integral equation (VIE) is proposed in this paper. In the forward EM problem, only the contrast of conductivity is solved by the electric field integral equation method. However, in the forward seismic problem, both the contrasts of velocity and mass density are solved by the combined field VIE method. Both forward solvers are accelerated by the fast Fourier transform. In the inversion problem, by using the petrophysical equations about the porosity and saturation and applying the chain rule, we fuse the EM and seismic data and construct the joint petrophysical inversion equations, which can be solved by the variational Born iteration method. Then, in order to further enhance the reconstructed results of the joint petrophysical inversion, we enforce the structural similarity constraint between porosity and water saturation and add the cross-gradient function to the joint petrophysical inversion cost function. Two typical geophysical models based on the remote sensing measurement are used to validate the proposed methods. One is the cross-well model, and the other is the marine surface exploration model. The advantage of the joint inversion compared with the separate inversion is evaluated based on the resolution and the data misfits of the reconstructed profiles as well as the antinoise ability. [ABSTRACT FROM AUTHOR]

Hydrocarbon play assessment of any hydrocarbon reservoir unit depends on the porosity, permeability, hydrocarbon saturation and water saturation of petrophysical model distributions and seismic reflections of reservoir rocks. The objective of the study is to resolve the ambiguities that are associated with hydrocarbon play assessment of an X-field in the Niger Delta basin. This was achieved through the use of pre-conditioned attributes, fault delineating seismic attributes such as coherence, variance and quantitative definition of the reservoir units of petrophysical model distributions, through the adoption of an integrated methodology of 3D seismic and well log data. A quick look examination of the well log signatures revealed numerous reservoir sand units, but only three hydrocarbon-bearing reservoir sands were of interest to us (RS1, RS2 and RS3). From the quantitative interpretation of well logs, the three identified reservoir sands were evaluated in terms of porosity, permeability, hydrocarbon saturation, shale volume, movable hydrocarbon index and water saturation. Effective porosity values of 24.56, 23.01 and 24.00% were obtained for Well 1, Well 2 and Well 4, respectively. This supports the known or already established porosity range of Agbada Formation of Niger Delta with range 28-32%. The hydrocarbon saturation for RS2 is 68.51% for Well 4, for RS3 72.49% for Well 3 and for RS2 74.16% and for RS3 77.34% for Well 2. RS2 of 79.51% and RS3 of 80.99% for Well 1 were obtained. This shows how prolific the reservoir sand units are with hydrocarbon accumulation tendencies. Structural analysis revealed a highly faulted system that depicts a typical tectonic setting of the Niger Delta basin, and the computed attributes like coherence, and variance shows an optimum visualization of the faulting system. This implies that the trapping mechanism of the field is of both anticlinal and fault-assisted closure and also the viability of the reservoir units is high from the computed petrophysical parameters. [ABSTRACT FROM AUTHOR]

A reservoir characterization study, using petrophysical and petrographic analyses, has been made on the Paleocene Farewell Formation in the Taranaki Basin, New Zealand, based on five selected wells. Farewell Formation is largely a sandstone formation belonging to the Kapuni Group. The integrated study has shown that Farewell Formation is a good promising reservoir with average effective porosity of 17.7% and permeability of 415 mD. The petrographic study indicates the occurrence of abundant intergranular and secondary pores. It also proved that the Farewell Formation has been affected by several diagenetic features. Compaction, cementation and clay mineral authigenesis are the most common. Quartz and feldspar overgrowths have been recorded in many samples, and secondary porosity due to dissolution is also observed. In general, good reservoir quality features are dominant in the Farewell Formation and diagenesis has little effect on the reservoir quality. These findings are supported by well log interpretation results, which confirm good sand and net pay zones are available with very low average water saturation (24.9%). [ABSTRACT FROM AUTHOR]

The study evaluates the petrophysical properties of the reservoir sands of the Chad basin Nigeria in an attempt to evaluate its prospect for hydrocarbon accumulation. The sand units within the Fika, Gongila and Bima Formations from 12 exploratory Wells drilled in the area were delineated in order to estimate the rock properties such as porosity, permeability, water saturation, hydrocarbon saturation and net-to-gross (NGR) values. The interpretation of the computed values suggests that the sandstone units in the basin have the potential to accumulate and transmit hydrocarbons. The thicknesses of the sand units vary from 10 to 360 m, with an average porosity of 26.62% for all the Wells. The permeability of the rocks ranges from 75 to 5600 mD, suggesting good to excellent while the hydrocarbon saturation of the interstitial spaces are between 3.64 and 83.78 %. Although the overall average porosity and permeability are within limits required for hydrocarbon generation and accumulation, the hydrocarbon saturation values suggest that some of the reservoir units in the basin might contain hydrocarbon in non-commercial quantities. [ABSTRACT FROM AUTHOR]

West Al Khilala Field is considered as gas producing from Abu Madi Miocene sandstone Formation. It lies at the central onshore Nile Delta and covers about 47.6 km 2 . The petrophysical parameters (porosity, permeability, water saturation and net-to-gross ratio) as well as static modelling of the Abu Madi reservoir from well logs are carried out. The porosity model reflected good porosity in the study area especially in the massive sandstone unit with values range from 18% to 27%, while low porosity value are recorded in the layered and basal sandstone units with values range from 1% to 24%. The permeability model displayed values range from 50 md to 2000 md in the massive sandstone unit that increases towards the southeast direction reflected a high promising for hydrocarbon prospecting. The permeability values of the layered and basal sandstone units range from 0.5 md to 700 md with mean value of 40 md reflected a tight permeability due to the presence of shale streaks. The water saturation (Sw) model of the layered and massive sandstone units indicated hydrocarbon-bearing intervals with values from 10% to 64.7%, while the basal sandstone unit is highly saturated with water from 65% up to 100%. The volumetric calculation of the reservoir showed that the reservoir contained about 246 BSCF as a recoverable gas. [ABSTRACT FROM AUTHOR]

Accurate estimation of permeability is essential in reservoir characterization and in determining fluid flow in porous media which greatly assists optimize the production of a field. Some of the permeability prediction techniques such as Porosity-Permeability transforms and recently artificial intelligence and neural networks are encouraging but still show moderate to good match to core data. This could be due to limitation to homogenous media while the knowledge about geology and heterogeneity is indirectly related or absent. The use of geological information from core description as in Lithofacies which includes digenetic information show a link to permeability when categorized into rock types exposed to similar depositional environment. The objective of this paper is to develop a robust combined workflow integrating geology and petrophysics and wireline logs in an extremely heterogeneous carbonate reservoir to accurately predict permeability. Permeability prediction is carried out using pattern recognition algorithm called multi-resolution graph-based clustering (MRGC). We will bench mark the prediction results with hard data from core and well test analysis. As a result, we showed how much better improvements are achieved in the permeability prediction when geology is integrated within the analysis. Finally, we use the predicted permeability as an input parameter in J-function and correct for uncertainties in saturation calculation produced by wireline logs using the classical Archie equation. Eventually, high level of confidence in hydrocarbon volumes estimation is reached when robust permeability and saturation height functions are estimated in presence of important geological details that are petrophysically meaningful. [ABSTRACT FROM AUTHOR]

Storage pre-feasibility study for the Romanian CCS Demo Project, CCS team has performed static modeling activities for the two sites selected in “Zone 1” and “Zone 5”. These activities were split in two steps for each site: structural modeling and property modeling. The data available at the time of the building of the static models consisted of the following:241 2D seismic lines across the entire Turceni area, 58 wells with some associated logs, of which notably -16 in “Zone 1”, of which 9 are “deep wells” (crossing the entire Sarmatian sequence) and 44 in “Zone 5”, of which 16 are “deep wells”. Some of these wells are shallow wells according with the TD and according with the bottom hole formation (they drilled only the upper part of the Sarmatian). All the others are deep wells, they have drilled almost the entire Sarmatian sequence, some of them found the Tertiary base. In the ‘wells with logs’ groups there are 16 deep wells and 28 shallow wells in Zone 5, 9 deep wells and 7 shallow wells in Zone 1 respectively. Using the logs, geological markers from the wells and all the geological information from the bibliography, technical reports and other sources, the Sarmatian deposits have been divided into several layers (Sa2, Sa3, Sa4, Sa5, Sa5a, Sa6, Sa7, Sa8), each of them characterized by different characteristics as can be seen on the wells correlations. The seismic lines have been acquired and processed according with the different technologies according with the available methods from the time when they have been acquired. In the area there are seismic lines acquired from 1973 till 2005. Some of the old seismic data have been reprocessed later on but due to the quality of the raw data the quality of the processed seismic lines did not improve too much. The Sarmatian deposits are characterized by parallel, horizontal seismic horizons with good continuity and variable amplitude according with lithological and fluid content changes. The faults are developed on different seismic lines but was very difficult to correlate from a line to another and in such a way to define if it is a fault with major importance and extension or is very local ones. Some of faults are developed only in the tertiary sequences that means that these are formed by gravitational processes done by differential compaction of lithological columns with different thickness which in general decrease in net slip in the upper part. Such kind of faults have a local development and because they affected an unconsolidated or poor consolidate geological formations they are close faults and not create an open space and in general these faults are formed above the uplifted blocks or a prominent high of the relief. Most of these wells have lithological marker information (well tops) and resistivity logs (including SP). However these logs have not been made available. One well has a GR log, 2 wells have a sonic log, 2 wells have a neutron log; 7 wells have checkshot information. While the seismic coverage appears sufficient to build a structural model with a reasonable level of detail for this stage, it is evident that the scarcity of petrophysical information is likely to affect the reliability of the property models. The static model from zone 1and zone 5 have been created using: fault modeling, pillar gridding, make horizons, make zones, layering, facies calculation, scale up well logs, facies modeling, properties modeling. The facies modeling, reflects the knowledge of the depositional environment of the site. The “regional” (depositional) facies respects the assumptions of the source rock and sedimentation direction; the methods chosen to model the lithofacies (“newfacies”), conditioned to each of depositional facies types defined above, appear adequate for the environment distribution of petrophysical properties (porosity and permeability) has been modeled separately for each facies type (petrophysical model conditioned to facies model). This is the recommended way to capture the lithological variations previously modeled. The source for these properties is normally the corresponding upscaled well logs. However, this is apparently not the case for the static models reviewed here: only the minimum and maximum values for each facies type were input in the petrophysical modeling process. Using the static model created for the two zones, 1 and 5, two injection areas have been selected for CO2 injection. The selection of these CO2 injection areas took in consideration the lithological content of geological formations from Sarmatian deposits, depth of the reservoirs, the existence of a proper seal rocks above the reservoirs. [ABSTRACT FROM AUTHOR]

The aim of this article is to provide a qualitative and quantitative description of Lower–Upper Cretaceous detrital rocks (Escucha and Utrillas sandstones) in order to explore their potential use as CO2 reservoirs based on their petrographic and petrophysical characteristics. Optical microscopy (OpM) and scanning electron microscopy (SEM) aided by optical image analysis (OIA) were used to get qualitative and quantitative information about mineralogy, texture and pore network structure. Complementary analyses by X-ray fluorescence (XRF) and X-ray diffraction (XRD) were performed to refine the mineralogical information and to obtain whole rock geochemical data. Furthermore, mercury injection capillary pressure analysis (MICP), the gas permeameter test (GPT) and the hydraulic test (HT) were applied to assess the potential storage capacity and the facility of fluid flow through the rocks. Both of these factors have an outstanding importance in the determination of CO2 reservoir potential. The applied petrophysical and petrographic methods allowed an exhaustive characterization of the samples and a preliminary assessment of their potential as a CO2 reservoir. The studied conglomerates and sandstones have a porosity range of 8–26% with a dominant pore size range of 80–500 μm. The grain skeleton consists of quartz (95%), very minor potassium feldspars (orthoclase) and a small amount of mica (muscovite and chlorite). According to these preliminary results, among the studied varieties, the Escucha sandstones have the most favorable properties for CO2 geological storage at the rock matrix scale.

The use of borehole imaging tools has become widespread in recent years with more specialized studies of reservoir properties, particularly in highly-porous and fractured carbonate systems. In this study, the Formation MicroScanner (FMS) borehole imaging tool and conventional well log data have been used to study the secondary porosity of the dolomitic Alamein Formation in the Alamein Field, north Western Desert, Egypt. Based on well log analyses of the formation from Tourmaline-1X and N.Alamein-6X wells, we show that secondary porosity occurs across the formation, and is filled mostly with hydrocarbon. We also show that the formation has good average effective porosity and hydrocarbon saturation. FMS images of the Tourmaline-1X well confirms that the formation is intermittently vuggy with solution-filled channels from the top to its base. The vug pores are observed to be well-connected, which supports good effective porosity values interpreted from petrophysical data. An additional set of core photographs of the Alamein Formation from N.Alamein-5X well confirms the presence of secondary pores, which are filled by hydrocarbon, and exhibit intense fluorescence under UV light. Our results show that the abundance of secondary porosity in Alamein Formation would play a key role in evaluating its reservoir quality and reservoir performance.

This study investigates petrophysical characteristics of lacustrine Permian Murteree and Roseneath shales in relation to reservoir evaluation of the most prospective gas shale plays in the Cooper Basin, Australia. Both shales were investigated for gas volumes by employing unconventional petrophysical techniques through a combination of source rock parameters acquired by geochemical analysis, and integrating the extracted parameters into log interpretation and core studies. Modeling mineralogical composition using wireline logs require the selection of a proper mineral model. In this study, the mineral model was built in the Interactive Petrophysics (IP's) Mineral Solver module by integrating all regional sedimentological, petrographic, SEM (Scanning electronic microscope), pulse decay and X-ray diffraction data (XRD) from core and chip cutting samples. This study developed a mineral grouping framework to assist in the selection of a proper model to easily solve complex shale gas reservoirs for gas volumes. Furthermore, the permeability of both shales depends on in-situ confining stress and permeability of these cores and can be calculated through decay rate of a pressure pulse applied to experimental data. Subsequent to the integrated study as explained above, it is concluded on the basis of extruded parameters (shale porosity, permeability, volume of kerogen, volume of brittle minerals and water saturation) that Murteree formation exhibits better potential than Roseneath formation in and around Nappameri, Patchawarra and Tenappera troughs, while poor potential is exhibited in the Allunga trough. The only location where Roseneath exhibits better potential is in Encounter-01 well. [ABSTRACT FROM AUTHOR]

Presence of sandstone streaks in Sidri Member within Belayim Formation that lies between two productive zones; Kareem Formation and Hammam Faraun Member, was the main reason to perform this study. It may represent a good hydrocarbon reservoir and will be added to the Egyptian oil production in some wells of Badri field. This Member has high resistivity signature on Electric-logs responses which attracted the attention to investigate its occurrence in the field, to delineate its distribution all-over the area, to evaluate the petrographic and petrophysical characteristics and to evaluate its productivity. Petrographic and petrophysical analyses of these sand zones were undertaken using thin section samples. The electric logs and subsurface geologic data was used to evaluate the main reservoir characteristics of the Sidri sandstone such as lithology, cementation, shale volume, porosity (Φ), effective porosity (Φ eff ), estimated permeability (K), fluid saturation, fluid type and Net pay thickness. This study revealed that, Sidri sandstone facies was classified into two mainly sandy facies; blocky sandy facies which located at the northern part of the field and streaky sandy facies at the southern area of the field. These two facies are separated by shaley facies. Some wells were studied to represent the two sandy facies in Sidri Member and these sand intervals have not been tested yet. These sands consist of quartz grains with grey and pink feldspars as accessory minerals, with siliceous and calcareous cementation, with good porosity. Petrophysical evaluation of this sand unit indicated that it is hydrocarbon bearing formation in three wells and water bearing one in other wells. Electrical logs analysis (Resistivity, Density-Neutron, Sonic and Gamma-Ray) revealed that The volume of shale in this sandstone, the effective porosity, the water saturation, the estimated permeability, the hydrocarbon saturation, and the net-pay thickness are varying from 9 to 13%, 19%–22%, 26%–34%, 200 and 600 mD, 66 and 74%, 20–35 feet respectively. The fluid types are oil, gas and water. [ABSTRACT FROM AUTHOR]

Geological and petrophysical parameters are critical in evaluating the production potential of prospective shale gas plays and their economic viability for commercial development. However, based on the US experience, these characteristics can vary widely. Furthermore, the non-marine shale plays of the Cooper Basin, South Australia are distinctively different from the marine shale plays in the US. Non-marine shale may consist of higher clay content and, thus, may be less responsive to hydraulic fracturing due to the increased ductility. Conversely, the availability of sufficient amounts of quartz and siderite may counteract this effect and maintain brittleness. In this study, the mineral, total organic and gas content, thermal maturity, Poisson's ratio and Young's modulus data obtained from the Roseneath and Murteree formations of the Cooper Basin have been compared with US shale formations. The results show that the formations compare well in terms of thickness, thermal maturity, Young's modulus and Poisson's ratio, but not in clay mineral content and formation temperature and values for TOC, porosity and gas-in-place are comparatively lower. To determine whether such plays are economically viable will require technical, as well as economic, analysis of the hydraulic fracturing process, including the potential for horizontal and vertical well development or basin centred gas developments. A shale play that has unfavourable prospects may have upfront infrastructure and major capital costs that outweigh the potential receipts from gas production. [ABSTRACT FROM AUTHOR]

The present study deals with petrophysical analysis and electrofacies zonation of the Nullipore carbonate reservoir rocks of Ras Fanar filed, Gulf of Suez-Egypt. The wire line logs of 14 wells, the available capillary pressure data, and the special core analyses of some cored intervals, as well as the coralline algae content, were analyzed and interpreted together for reservoir evaluation and zonation. Three electro-lithofacies zones (I, II, and III) are detected. However, zone (II) is considered the most important, in terms of the high porosity (18%) and hydrocarbon saturation (80%), which it attains. The petrophysical analysis of the Nullipore reservoirs shows two lobes (A and B) of good hydrocarbon potentialities, extending along northwest-southeast direction. However, “B” lobe attains better reservoir quality than “A” lobe. Net pay cutoff values of 14% and 65% are taken for porosity and water saturation, respectively. [ABSTRACT FROM PUBLISHER]

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