Petrophysical Evaluation Research Articles

Petrophysical evaluation of the Oligocene Reservoirs in Well A13-NC59, Gialo Field, NC59 Concession, Southeast Sirt Basin, Libya

Petrophysical evaluation of the Oligocene Reservoirs in Well A13-NC59, Gialo Field, NC59 Concession, Southeast Sirt Basin, Libya

Assessment of Reservoir Quality of the Cretaceous Yolde Sandstone: A Case Study of Doma Stream, Gongola Basin, Northern Benue Trough, Northeast Nigeria.

Sedimentology, petrography and petrophysical studies were applied to the Cretaceous Yolde Formation sediments along the Doma stream, to evaluate its reservoir quality. The Yolde Formation along the Doma Stream is composed of lithologies that are laterally extensive and have reached a thickness of about 80m. They are lithologically made of sandstones with dark grey mudstones, laminated shales and grey to pale yellow limestones. The Sandstones are structurally characterized by planar, tabular and trough cross-beds, convolute beds, and hummocky cross-stratifications with reactivation surfaces. Some of the sediments are bioturbated. The petrophysical evaluation indicated porosity values ranging from 6% to 26%, and permeability values between 12.7mD and 108mD. These values are comparable to the reservoir rocks of proven petroleum basins of the North Sea and Niger Delta. Therefore, the Yolde Sandstones of the study area can have great potential to serve as good reservoir rock in the Gongola Basin.

Petrophysical Analysis of Mars Field Offshore Dahomey Basin Nigeria

Petrophysical evaluation of the Mars Field in the Dahomey Basin, Nigeria was done to identify and analyze petrophysical properties of the reservoirs in the field. This was achieved by the use of 3 wells from the field. This research determines the lithology, shale volume (Vsh), porosity (Φ), permeability (K), fluid saturation. Two hydrocarbon-bearing reservoirs age from three wells were identified which was then subdivided into different levels in this research. The average permeability value of the reservoirs is 20.0140md while porosity value ranges between 18%-39%. Fluid types within the reservoir were identified to be Gas, Oil, Condensate and water based on the Neutron-Density log motif. The petrophysical analysis of the field reveals that reservoir porosity ranges from 11-26%, hydrocarbon saturation ranges from 0.07-0.91, water saturation ranges from 0.93-0.09, volume of shale ranges from 0.09-0.22 and net-to-gross ranges from 0.46-0.878. From this research it was identified that the prolific reservoir within the Dahomey basin is within the Turonian and Cenomanian reservoir with good quality reservoir and producible hydrocarbon saturation. Keywords:Dahomey/Benin Basin; Petrophysics; Volume of shale; Porosity; Water saturation; Potential reservoir; Turonian; Cenomanian.

Petrophysical Evaluation of H-field, Niger Delta Basin for Petroleum Plays and Prospects

Abstract in English As a result of a combination of several methodologies, the H-Field, Niger-Delta, has been delineated. To identify probable reservoirs, seals, and source rocks in the study area, this study integrates sequence stratigraphy with petrophysical concepts through a comprehensive analysis of 3D seismic and well logging datasets. According to the 3D facies model, reservoirs are dominated by sand and are laterally extensive. They were then upscaled and stochastically distributed to create a 3D reservoir property model. On average, the porosity of these clastic reservoirs ranges from 22 to 28%. Reservoir net-to-gross (NTG) ratios range from 0.67 to 0.96. Water saturation ranges from 8% to 30%, while hydrocarbon saturation ranges from 70% to 92%. Four gas-bearing units and six oil-bearing units are present in reservoirs P 0.5 and P 1 compartments. All reservoir intervals’ oil and gas volumes are evaluated based on the hydrocarbon distribution. Geological models of the subsurface, such as the one in this paper, are crucial for future reservoir development programs.

Petrofacies-Dependent Cementation Factor Relationship for Low-Resistivity Miocene Carbonates: Mumbai Offshore Basin

Summary In Mumbai offshore, Miocene carbonates are deposited with intermediate clastic inputs under cyclic sea level changes and have undergone diagenesis from time to time. Miocene carbonate layers deposited southwest of Mumbai High are producing a good amount of hydrocarbon from 1 to 2 Ω·m resistivity pays. A total of 58 representative core plugs from four different wells were studied to identify the reason for low resistivity and to classify rock facies types and porosity systems using scanning electron microscopy (SEM), thin-section nuclear magnetic resonance (NMR), and petrophysical core data. It was observed from the core study that Miocene carbonates have complex porosity systems and mud-supported to grain-supported reservoir facies. Dominance of mud-supported matrix is the main reason for low resistivity in Miocene carbonate layers as observed from integrated advanced log and core studies. Conventional petrophysical evaluation using constant petrophysical parameters (a, m, n) or linear correlation of cementation factor with porosity can lead to erroneous results in this scenario. A petrofacies-dependent correlation among cementation factor and porosity is attempted in this study for realistic evaluation of low-resistivity carbonate reservoirs. Different cementation factors vs. porosity relations have been derived for various carbonate formations worldwide. Shell formula demonstrates that cementation factor increases with decreasing porosity while correlation derived by Borai and Rafiee brought out inverse relation among cementation factors with porosity in tight carbonates and is providing almost constant cementation factor beyond 0.2. But, in our study, a core porosity-cementation factor plot of reservoir facies is showing that below 0.1, m values are increasing with increase of porosity, which is contradictory to Shell formula. This trend of cementation factor at low porosities is due to the presence of secondary porosity. In the porosity range 0.1–0.25, cementation factor increases eventually with the increase of porosity, but beyond porosity values 0.25, increase in porosity causes decrease of cementation factor. This is due to increasing content of mud-supported matrix, which is overall increasing the total porosity but eventually decreasing cementation in a rock. A new nonlinear correlation has been established between m and porosity for Miocene carbonates of Mumbai offshore area, by incorporating all the factors affecting cementation factor (m). Finally, saturation estimated using variable m either using newly established core derived correlation or resistivity image data is giving representative and improved saturation against low-resistivity reservoir layers compared with constant m.

Petrophysical Evaluation of Mishrif Formation in X oilfield, southeastern Iraq

Well logs data was analyzed and used to identify reservoir properties. The Mishrif Formation was sudivided into six units (MA, MB1, MB2, MC1, MC2 and MC3) with different potential characteristics. By using the MID method and M-N cross plots to determine the rock and mineral composition of the Mishrif Formation in the X oil field, it was found through the profiles that the Mishrif Formation consists largely of limestone, little dolomite and shale. Based on the CPI results of the two wells (XA and XB)it was noted that the units BM1, BM2 and MC1 reservoir units have good petrophysical properties as they had good porosity ranging from 0.1 to 0.19 with low values of water saturation (0.3-0.79) and shale volume (0.0295-0.070) respectively). Due to these characteristics these units are considered oil-bearing areas are among the most important units in the Mishrif Formation in the X field. while the other units (MA, MC2 and MC3) are considered non-reservoir units due to It has poor petrophysical properties.

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

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

Petrophysical Characterization of Shaly Sand Reservoirs in Well UK-05 Eastern Niger Delta Basin, Nigeria

A petrophysical evaluation of Well UK-05 in the eastern Niger Delta Basin was carried out in order to determine reservoir zones, their porosity, permeability, fluid saturation and the effect of shaliness on the petrophysical parameters. Using interactive petrophysics software version 3.5, twenty five (25) reservoir zones were identified. The porosity values range from 15.77- 4.66% and permeability from 2.76-546.54 mD. The Archie’s, Simandoux, Dual-porosity, Waxman and Smith, and the Indonesian models were used to determine the fluid saturation. The water and hydrocarbon saturation values using the Indonesian model are 21.67-50.49% and 49.51-78.33% respectively. They slightly differ from the ones obtained using Simandoux, Dual Water and Waxman and Smith model (20.72-49.88% and 50.12- 9.22%, 18.26-50.49% and 49.51-81.74%, 14.67-48.26% and 51.74-5.33% for water and hydrocarbon saturation respectively). The interpreted lithology shows that the formation penetrated by the Well UK-05 is dominated by alternating sands and shales with the sand being the dominant lithology. These lithostratigraphic characteristics correspond to those of the parallic Agbada Formation. The effective porosity values obtained range from 14.93 to 34.66%, which are lower than 0.013% to 94.08% obtained by other authors since they did not take into consideration the effect of shaliness. This shows that the more the shale volume, the higher the uncertainty of actual porosity of the reservoir.

Reservoir properties and petrophysical analysis of the Late Miocene Abu Madi Formation in the Abu Qir Bay Area, West Nile Delta, Egypt

The Abu Qir Bay area is on the offshore western part of the Nile Delta. It is divided into three fields namely: North Abu Qir, Abu Qir, and West Abu Qir. The main reservoir in the Abu Qir Bay area is Abu Madi Formation, which represents the Miocene rocks. The current uses conducting advanced conventional petrophysical techniques for determining the reservoir properties of the Abu Madi Formation. The wireline log data is commencing four wells drilled in the study area namely: North Abu Qir-7x, West Abu Qir-1x, Abu Qir-1x, and Abu Qir-13x). The interpreted lithologic data of the studied wire-line logs shows that the Abu Madi Formation’s main lithology consists of sandstone interbedded with some amounts of shale and thin lamina of limestone and anhydrite. Based on the interpreted well logging records, the Abu Madi Formation can be subdivided into three members: The Upper, Middle, and Lower Abu Madi members. The main target is the Upper Abu Madi members with shale volume varying from 8 to 12% with an average of 10%. The Middle Abu Madi member which is considered the second target has a shale volume ranging from 9.5 to 13.5% with an average of 11.5%. The thickness of the Abu Madi Formation ranges in the four drilled wells varies between 67.61 and 167.63 m with an average of 117 m. The petrophysical evaluation displays two important pay zones, and they belong to the Upper and the Middle Abu Madi members. The average porosity and hydrocarbon saturation values of both members indicate that Abu Madi is a very good reservoir. The southwestern area near West Abu Qir-1x well was found a good place for any upcoming appraisal, particularly for the upper Abu Madi reservoir future development.

Petrophysical evaluation of the Lower Permian formation as a potential reservoir for CO2 - EGS – Case study from NW Poland

Petrophysical evaluation of the Lower Permian formation was performed on the basis of the results of laboratory tests of rocks including pore space investigations using the Mercury Injection Capillary Pressure (MICP) method, the pore space saturation measurements by the Nuclear Magnetic Resonance (NMR) method, and measurements of the thermal conductivity coefficient by FOX series heat flow meters based on the one-dimensional Fourier equation. Three types of rocks: sandstones, conglomerates and effusive, sampled from the Ośno IG-2 well located in the Gorzów Block (NW part of Poland) were analysed. 42 core samples from the depth interval of 3212–3659 m bgl were tested. The results provide a wide range of information about the sample, primarily such parameters as pore size distribution, effective porosity and permeability, bulk density, sketal density, and thermal conductivity. The aim of the study was to determine the relevance of Lower Permian formation as a geothermal reservoir for CO2 – EGS - Enhanced Geothermal Systems, which use carbon dioxide instead of water as working medium. Although worldwide research on such systems has been going on for many years, so far it has not been realized on a commercial scale. Moreover, to date there are no EGS installations in Poland. The ongoing research aims to bring the construction of the first pilot installation in Poland closer. Effusive rocks were characterized by lower value differentiation and relatively high lambda values (average 1.77–1.81 W/mK for dry samples, 2 W/mK for fully saturated and 2.1 W/mK for a mixture of water and CO2), average effective porosity of 7.92% and permeability of 0.055 mD. Sandstones have the highest thermal conductivity values (1.87 W/mK at 20 °C, 1.87 W/mK at 50 °C, 1.82 W/mK at 100 °C and 1.79 W/mK at 150 °C), average effective porosity 5.56%, and permeability of 0.133 mD. For the conglomerates, the lowest values of thermal conductivity were obtained (average value for water-saturated sample equal 1.7 W/mK and for dry sample 1.4 W/mK). The average value of effective porosity for conglomerates is 7.66% and the permeability is 0.141 mD. The results indicate that the studied rocks have suitable parameters as a geothermal reservoir for CO2-EGS, especially effusive rocks. These parameters are similar to those of reservoir rocks for the EGS installation in Groß Schönebeck, as well as all types of rocks are classified primarily as petrothermal EGS.

Experimental Study on the Impact of Clay Distribution and Mineralogy on NMR T2 and Internal Gradient: Insights From Well-Controlled Physical Samples

Summary Nuclear magnetic resonance (NMR) is a reliable tool for petrophysical evaluation and the characterization of pore structures. Compared to conventional carbonate reservoirs, sandstone reservoirs contain higher amounts of ferromagnetic and paramagnetic ions (such as iron, nickel, or manganese) usually found in microporous clay aggregates. The interpretation of petrophysical data in sandstone formations can be complicated by variations in clay mineralogy and distribution patterns (laminated, structural, and dispersed). Nevertheless, the impact of clay distribution patterns on NMR signals is not well understood. This study aims to investigate the impact of clay mineralogy and distribution patterns on the T2 relaxation times and internal gradient (i.e., inhomogeneity in the magnetic field). Glass beads were mixed with three different clay minerals characterized by no iron content (kaolinite) to higher iron content (illite and nontronite). The bead-clay mixtures were prepared at a fixed clay content but with variable clay distribution patterns to examine the impact of clay distribution alone. NMR T2 measurements at several echo times were performed on the pure glass beads and the mixtures to evaluate how clay mineralogy and distribution patterns affect the T2 and the internal gradient of the host glass beads. At a given clay distribution pattern, a more significant decrease in T2 relaxation times and a larger increase in the internal gradient of glass beads were observed when adding clays with higher iron content. This is explained by the higher surface relaxivity, and magnetic susceptibility caused when introducing clay with higher iron content. Such an impact can complicate the characterization of NMR-derived pore sizes as similar pore size distribution (PSD) can have very different T2 distribution and the logarithmic mean of T2 relaxation time distribution (T2LM) values. Micro-computed tomography (µCT) images were acquired to compute the PSD to compare it with ones obtained from the NMR measurements. The PSD for the three clay minerals showed almost the same distribution using µCT; however, they showed totally different T2 relaxation times distributions. That is due to the significant impact of the internal gradient causing a distortion in the magnetic field. Thus, careful consideration must be taken before converting the NMR data into PSD. The introduction of iron-free kaolinite resulted in a negligible impact on the internal gradient of glass beads regardless of the clay distribution pattern. On the other hand, the addition of dispersed iron-rich clays (illite and nontronite) results in up to two orders of magnitude increase in internal gradients, compared to mixtures with laminated and structural clays (at the same clay mineralogy and content). Moreover, dispersed clay mixtures display larger changes in T2LM and porosity as a function of increasing echo time. The results from this study suggest that changes in T2LM and the logarithmic mean of the effective internal gradient distribution geff,LM, compared to the clean host sand, can provide insight into iron-rich clay distribution. Larger changes in any given clay content and mineralogy would suggest a more dominant dispersed clay distribution while negligible changes would suggest a laminated distribution.

Petrophysical characterization and formation evaluation of sandstone reservoir: Case study from Shahd field, Western Desert, Egypt

This paper aims to establish a complete workflow for a petrophysical evaluation to enhance and quantify hydrocarbon prospect and productivity of Shahd SE field, East Ras Qattara concession, Western desert, Egypt. The suggested workflow can, then, be used with the same steps and sequences for any petrophysical evaluation study. Well logs data from four wells were used for this study. The present data has drilled through three formations: (1) Bahariya Formation, which has been divided into two subzones; (I) Upper Bahariya, a shaly formation and (II) Lower Bahariya, the main reservoir present in our case study. (2) Kharita Formation, which consist of clean sand. We will evaluate the three most useful petrophysical parameters: (a) volume of shale (Vsh) using the gamma-ray (GR), (b) effective porosity Φeff) using the neutron log and the resulting volume of shale as an input, and (c) water saturation (Sw). Several equations were used to calculate the Sw. The best equation was Simandoux equation to put in consideration the shale model of the upper Bahariya. The results show that the net reservoir and net pay thicknesses were seen very promising in all four wells, all at the lower Bahariya Formation. The reservoir quality parameters "Effective Porosity (Φeff)" were almost the same for all four wells, as well as the high hydrocarbon saturation "Sh" for all four wells.

Characterization of elastic moduli with anisotropic rock physics templates considering mineralogy, fluid, porosity, and pore-structure: A case study in Volve field, North Sea

A practical methodology was designed to characterize mineralogy and the rock microstructure by constructing anisotropic rock physics templates (ARPTs) based on the Effective Medium Method (EMM). The ARPTs consider parameters such as pore aspect ratio (α), porosity, fluid saturation, and elastic properties of rock minerals. A three-stage methodology was applied to an oil well for a sandstone formation in the Volve field, North Sea. The first stage is the petrophysical evaluation, which is validated with core data. The second, the inversion scheme with differential effective medium (DEM) was used to predict aspect ratios in depth. The obtained results characterize the sandy formation setting intergranular porosity with 0.12 < α < 0.3, although there is also the presence of stylolites caused by the dissolution mechanism between quartz, feldspar, mica, calcite, and clay. The validation of the pore-structure is accomplished with thin sections. The last stage comprises the construction of ARPTs, which includes the axial and two transversal templates of Young's modulus versus Poisson's ratio. These templates are used to characterize lithology, porosity, pore-structure, and the mechanical behavior of the sandstone formation from well logs and gave invaluable information about the pay zone. In addition, because the lithotype interpretation proposed is merely borne by rock's elastic properties, it has the potential to be scaled to field scale by using seismic inversion data.

Depositional sequences and petrophysical evaluation to predict potential prospects of clastic reservoirs of “Olu” field, onshore Niger Delta

Depositional sequences and petrophysical evaluation to predict potential prospects of clastic reservoirs of “Olu” field, onshore Niger Delta

Improving the 3D facies model with the seismic-derived log volumes: a case study from the Asmari Formation in the Hendijan Field, southwest Iran

Abstract The prolific Oligocene-Miocene Asmari Formation is the primary reservoir rock hosting important hydrocarbon resources in Iran and consists of fluvial/deltaic siliciclastic and shallow marine carbonate rocks in the Hendijan Field. Due to the significant facies variability of the formation, the presence and quality of the reservoir pose a significant uncertainty in the characterization of the reservoir. This study compares two facies models, one based on well logs only and the second based on estimated facies volumes as a secondary variable in facies modelling. The petrophysical evaluation with microscopic thin sections and electrofacies analysis were used to classify the facies and determine the reservoir quality. As a result, the Ghar Member was identified as a highly porous interval, while the lower part of the Asmari Formation is characterized by tight facies. A sequential Gaussian simulation (SIS) algorithm was used to build the 3D facies model on the basis of the well logs. Acoustic impedance, shear impedance and density (derived from pre-stack inversion) were used as inputs to an artificial neural network to generate acoustic and density log volumes. Using electrofacies cut-offs, facies volume was constructed and used as a secondary variable to improve the initial facies model. The final facies model was compared with the blind well to check the validity of the prediction and satisfactory results were obtained. Since the values are present in all the cells of the reservoir (the traditional facies model only has values for the well location), the estimated facies volume is an accurate variable in the prediction of the facies model for the Asmari reservoir and for this reason the secondary facies model is more reliable than the primary one.

Hydrocarbon play assessment of the sapele field, for moveable hydrocarbon indices, onshore niger delta.

A field's hydrocarbon evaluation takes into account the productivity of the hydrocarbon reservoir bearing unit. It basically includes a thorough examination of the geological interpretation of petrophysical parameter indices deduced from well logs. This study uses MHI and proven integrated methodologies including well logs analysis, petrophysical computing, to evaluate the Sapele-field with the objective of establishing its fluid types and hydrocarbon saturations. Three formations across eight wells in the field were delineated using the quick look analysis approach at low gamma ray intervals corresponding to high resistivity kicks. Correlation of the wells was conducted to specifically check the continuity in stratigraphy of the formations across the wells. Petrophysical parameters evaluation were conducted to qualitatively access the formations across the eight wells. Porosity, permeability, water saturation, Net pay thickness, water saturation and MHI were calculated as first and second degrees petrophysical parameters. Results revealed a characteristic thin beddings in the formation across the eight wells, with the same range of net pay thickness. MHI results (0.24-0.61) revealed the formations hydrocarbons are moveable during invasion and this is in agreement with the formations tendencies to accommodate and transmit hydrocarbon (0.14-0.24 porosities and over 250mD) with good hydrocarbon saturations of over 55%. This study has shown that the Sapele field is viable with good hydrocarbon mobility tendency during invasion.

Petroleum Potentiality and Petrophysical Evaluation of Late Triassic Baluti Formation, Northern Iraq

Source rock potentiality and reservoir characteristics of the Baluti Formation (Late Triassic), Northern Iraq were examined in order to determine the hydrocarbon generation potential and reservoir properties. A combination of geochemical analyses, stable carbon isotope, 1D-basin modeling and digital log data were used to evaluate the formation. The Total Organic Carbon ratios range from 0.39 to 0.61 wt%, while the quantity of free hydrocarbon and residual hydrocarbon are low (0.05-0.11, 0.40-0.90 mg/g respectively). The average of oxygen index is 318 mg CO2/g TOC, while the hydrogen index is less than 200 mg HC/g TOC, which indicates type III kerogen. The outcomes of the pristane/phytane and Pr/n-C17 with Ph/n-C18 ratios suggest that the formation was deposited under oxic environment. This conclusion is also supported by trace elemental data. According to the average of Ro% of 0.58 and Tmax of 430.1oC, the formation is in immature to early mature stage. From a plot of 1D-modeled Ro% versus time, it is inferred that the organic matter of the formation had reached early maturation in the Early Paleocene (63Ma). The Baluti is waxier formation and the degree of waxiness ranges from 1.99-2.55. Regarding to, Triterpanes (Tm/Ts) and regular sterane C27-C29 the studied formation has deposited in terrestrial environment with high terrigenous input with hot and arid to semiarid climates. This result is supported by stable carbon isotopic data and clay mineralogy. Porosity of the dolomite beds is 10-15%. Based on the cutoff results, the Baluti Formation has only 1.13m net pay of 72m thickness, which means that the formation has poor porosity and permeability in the reservoir beds.

Jurassic-Lower Cretaceous petroleum system of Faghur Basin, North Western Desert, Egypt

Different parts of the Lower Cretaceous Alam El Bueib (AEB) and the Jurassic Khatatba source and reservoir rock units in the Faghur basin, like in other basins in the north Western Desert, act as hydrocarbon sources and reservoirs. In the present study, well-log data from five wells in Phiops field and geochemical data from the Neith S-2X well from the neighbor Neith field together with reflection 2D seismic data of thirty (30) lines have been utilized to evaluate the Jurassic-Lower Cretaceous petroleum system in the Faghur basin and to give evidence for future hydrocarbon exploration and development in the study area. Source rock evaluation shows that several units from both Alam El Bueib and the Jurassic Khatatba shale source rocks represent good source rocks. Total organic carbon (TOC) values of the studied units of Alam El Bueib shale source rocks range from 0.27 to 6.39 wt.% that reflect fair to very good source rock, while Toc value for the Alam El Bueib-6 shale source rock is 2.52 wt.% that indicates a very good source rock. These units are characterized by type (III) kerogen, reflecting their ability to produce gas with minor oil. On the other hand, the characterization of the Khatatba shale source rocks indicates a very good to fair organic richness and a type (III) kerogen with an input of type (II) as well, which appears their ability to generate gas with minor oil. Most of Alam El Bueib and Khatatba shale source rocks are found to be in the mature stage. Petrophysical evaluation indicates four definite reservoir units from the Alam El Bueib reservoirs (Alam El Bueib-3D, Alam El Bueib-3E, Alam El Bueib-3G, Alam El Bueib-6) and the Khatatba reservoir. Values for the net reservoir, hydrocarbon saturation, and water saturation indicate that these units represent very promising reservoirs in the studied Phiops field in Faghur basin. Local intra-formational shale intervals most probably seal these reservoirs in the AEB and carbonate interval of the Masajid Formation in the Khatatba Formation. Moreover, analysis and interpretation of the 2D seismic lines showed that both structural and stratigraphic traps dominate. Integration of geochemical, petrophysical, and seismic results, in light of available geological information, indicates a complete Mesozoic petroleum system in the Faghur basin.

Reservoir quality evaluation using sedimentological and petrophysical characterization of deep-water turbidites: A case study of Tariki Sandstone Member, Taranaki Basin, New Zealand

The current study aims to ascertain the reservoir characteristics of the Tariki Sandstone Member of the Otaraoa Formation, Taranaki Basin, New Zealand. This study was carried out by integrating the comprehensive petrophysical evaluation, sedimentological and petrographic studies, as well as well log analysis by using data from six wells. The porosity-permeability relationship is used to divide the samples of the Tariki Sandstone Member into reservoir and non-reservoir facies. A thorough petrophysical analysis shows that the maximum porosity values fluctuate between 16.6% and 22.1%, while permeability ranges from 102 mD to 574 mD, which indicates fair to good reservoir quality. Moreover, the Tariki sandstone represents six hydraulic flow units with a high reservoir quality index and flow zone indicator representing good reservoir characteristics. The pore size varies between nano and megapores with dominant macropores. Based on the sedimentological and petrographic analysis, the Tariki Sandstone Member is classified as a combination of subarkose, arkose, and lithic arkose with fine to medium and moderately to moderately well-sorted grains. The main diagenetic factor affecting the reservoir quality is cementation, which occupied all the pores with calcite. On the bright side, the secondary pores are developed due to the dissolution of calcite cement and few grains. The well log analysis demonstrates the presence of low clay volume ranging from 0.3% to 3.1%, fair to good effective porosity values between 13.6% and 15.9%, net pay thickness from 18.29 m to 91.44 m, and hydrocarbon saturation from 56% to 77.9%. The findings from this study revealed that the Tariki Sandstone Member possesses fair to good reservoir quality and hydrocarbon potential, which indicate submarine fans as appealing hydrocarbon reservoirs. This study can be used in similar depositional environments elsewhere in the world.

Petrophysical Evaluation of the Lower Rudeis Formation in Shukheir Bay Field, Gulf of Suez, Egypt Using Open-Hole Well-Logs

The Shukheir Bay Field is located in the northern part of the Shukheir Marine Concession towards the southern part of the Gulf of Suez, about 300 km southeast of Cairo. It covers a shallow offshore water area of 5 km2 with a total area of 22.5 km2. The Rudeis sands in the Miocene sequence, which are widely distributed in the area, represent the main reservoir in the Shukheir Bay field. This study focuses on the clastic unit in the Lower Rudeis Formation usually referred to as the Lower Rudeis Sandstone. The petrophysical evaluation of this sand zone was conducted using a complete set of open-hole well-logs in three wells penetrating the formation. The lithologic composition is distinguished and identified as sand intercalated with shale, using tri and dia porosity cross plots. The shale distribution has been studied in both ways, amount and type. The amount is found to be relatively low to moderate, and the type is found to be mainly dispersed shale as indicated by the Thomas-Stieber model and the dispersed-laminated plot. The net-pay thickness also has a good value ranging from 39 m to about 42 m with high porosity (21%) and good oil saturation (76-94%). Both the vertical and lateral distributions of the petrophysical parameters are clarified, using the proper types of graphs. This research recommends drilling development wells in the central part of the study area, in addition to increase the exploration process towards the southwestern part.