Shale Volume Research Articles

Delineation of the reservoir petrophysical parameters from well logs validated by the core samples case study Sitra field, Western Desert, Egypt.

In the northern section of the Western Desert, there are many extremely profitable petroleum and natural gas deposits in the Abu EL-Gharadig Basin. This study aims to highlight the hydrocarbon potential of Abu Roash F Formation, which stands for high organic content unconventional tight reservoirs, and Abu Roash G Formation which stands for conventional sand reservoirs, in Sitra field located in the central-western part of the Abu EL-Gharadig Basin. The research employed well-log data from four wells to ascertain petrophysical properties combined with core samples of two wells for a comprehensive examination and description of lithology. Initially, we commenced the execution of petrophysical analysis, encompassing log quality control procedures. Subsequently, we identified and revealed zones of interest and hydrocarbon indicators in both formations. Additionally, we ascertained the three most influential parameters, shale Volume, effective Porosity, and water saturation, which serve as defining factors for reservoir quality. Subsequently, an examination of the core samples, which encompassed lithologic description, lithofacies analysis, paleoenvironmental interpretation, petrographic analysis, and porosity assessment is conducted. For the sake of a more accurate interpretation, we conclude our research with cartographic maps created to evaluate the geographical distribution of hydrocarbon potential based on petrophysical characteristics, Distribution of the net-to-gross ratio among wells by correlating the litho-saturation models (rock models) for the four wells. The foregoing results declare that The Abu Roash F carbonate-rich rocks are a contender for unconventional tight oil reservoir potential with thin secondary porosity and high organic content, which normally requires a kind of hydraulic fracturing for prospective oil extraction, Furthermore, the upper section of Abu Roash G formation, particularly in well sitra8-03, has highly favorable conventional reservoir characteristics.

Practical approach for sand-shale mixtures classification based on rocks multi-physical properties

Sandstones are the most common reservoir rocks, providing reservoirs for oil and gas and serving as reservoirs for groundwater. The Gulf of Mexico is known for its sand-shale mixtures and potential for its oil and hydrate gas resources in sandstone units. Understanding these variations is essential for assessing hydrocarbon potential and unconventional prospectivity. In this study, we utilized the Elastic, Electrical, and Radioactive (EER) properties of rocks for lithological categorization of well logging data, leading to the development of a novel rock physics template. The electrical and radioactive properties of the rocks facilitated a broad lithological classification, while their elastic characteristics helped distinguish between porous and low-porosity zones. Electrical and radioactive properties are utilized for well data classification because in sandstone formations, there is a decrease in log gamma and an increase in log resistivity. As a result, these opposing shifts in the two geophysical logs enhance the spread of data points on the lithological resistivity-gamma ray scatter plot, thereby simplifying the process of lithological categorization. Ultimately, the well logging data was sorted into three distinct categories: low shale sands (shale volume < 30 %), sand-shale mixtures (shale volume = 30 to 80 %), and shale-dominated areas. Subsequently, the Thomas Stieber model was employed to identify the types of clay minerals present in both sandstones and sand-shale mixtures. The model's findings revealed that dispersed type clay minerals are predominantly found in sandstones, with laminar and structured types being relatively rare. However, in sand-shale mixtures, both dispersed and laminar clays observed.

Identification of Shale Layer in Offshore Field of North East Java Basin for Non-Conventional Oil and Gas Exploration

&lt;p&gt;Non-conventional hydrocarbon exploration is one way to develop shale potential to increase oil and gas reserves in Indonesia. Shale is a rock that is rich in organic material and is a target for non-conventional exploration, because it functions as a source and reservoir rock with a large shale volume and low permeability. Isopach maps can represent the thickness of shale layers and have the potential to become non-conventional exploration targets located in thick shale layers. Based on this background, this research will identify shale layers in the offshore fields of the North East Java Basin for non-conventional oil and gas exploration. The methods used are well logging and seismic methods. This research focuses on determining the location of shale layer depocenters based on isopach maps as a first step in localizing areas that will be targeted for the development of non-conventional hydrocarbon exploration. This research uses 29 2D seismic lines and 2 well data, namely NP-1 and NP-2 wells and the research target is the Kujung Formation and Ngimbang Formation in the offshore area of the North East Java Basin. The results obtained from the isopach map show that the depocenter location of the Kujung Formation is in the northwest direction with a shale thickness of 600-800 meters, while the Ngimbang Formation is in the east direction with a shale thickness of 1000-1300 meters. From the depocenter location, it can be seen that this location has a wealth of organic material so it has the potential to become a source rock and reservoir.&lt;/p&gt;

Optimizing reservoir characterization: insights from integrated data analysis

The Onshore Hydrocarbon prospectivity of the Niger Delta X-field is examined through the integration of 3D seismic and recorded information from well log data. Probable reservoirs of hydrocarbon-bearing were delineated to tackle the non-uniqueness in the identification of hydrocarbon quantity of concern. Three significant faulting patterns or systems were delineated and their architectural attributes depict a typical Niger Delta embedded anticlinal structural pattern. The study field exhibited both synthetic and antithetic structures, hence only fault on delineated reservoirs was used for structural modeling. All well locations were sited within the fault-supported synthetic and anticlinal structures and the static characteristics within the well coordinates were analyzed through petrophysical assessment. Depicted reservoir sands show low gamma ray readings, low volume of shale, considerate hydrocarbon saturation and low water saturation. The established petrophysical models showed a better net-to-gross (NTG) ratio, for the entire delineated reservoir units. This has contributed to the assessment of hydrocarbon-bearing reservoir units before employing the strategy for field development scenario, in order to eliminate dry hole drilling campaign. These will contribute to the reduction of operational costs, having delineated the accurate geometry and petrophysical model of hydrocarbon reservoir units.

Prediction of Sand Production from Poorly Consolidated Formations Using Artificial Neural Network: A Case Study, Nahr Umr Formation in Subba Oil Field

Sand production in poorly consolidated formations is a significant challenge to the oil and gas industry, resulting in reduced production and compromised equipment integrity. The oil and gas industry has recently become interested in data analytics because it has significantly simplified, accelerated, and reduced the cost of data visualization. The intriguing new approaches in artificial intelligence development promise to offer long-term solutions to the increasing problems affecting the petroleum industry's operations. Any completion operation in sandstone formations is based on determining whether or not a well will produce sand. It is economically unfavorable to the Nahr Umr Formation to install sand control equipment for wells that don't produce sand. This study aims to create an efficient and precise artificial neural network that can predict sanding in sandstone formations. To achieve this, we developed a two-layered ANN with a back-propagation algorithm using JMP software. The model formulation included various geological and mechanical factors that could impact sand detachment, such as Young’s modulus (YME), Poisson’s ratio, minimum and maximum horizontal stresses (SHMIN and SHMAX), pore pressure, shale volume, and formation strength. The study acquired data from both local fields, specifically the Amarah oilfield, and non-local fields from the literature. Two sets were created from the data: a training set comprising 75% of the data, and a test set comprising 25% of the data, both of which were classified. The speed and accuracy of a learning process in an Artificial Neural Network depends on the size of the data set, the number of hidden layers, and the input parameters. The statistical measures such as accuracy, confusion matrix, root mean square error, and generalized RSquare demonstrate the strong efficacy of the created Artificial Neural Network model. The results indicate a significant likelihood of sand production occurring over the perforation intervals across Su-4 and Su-5 wells. The method's unique feature is its ability to isolate shale areas and identify weak areas capable of producing sand in sandstone formations. In conclusion, it is determined that an Artificial Neural Network employing the back-propagation algorithm is a simple, reliable, and easy-to-use method for accurately predicting sand production.

Robust estimation of hydrogeological parameters from wireline logs usingsemi-supervised deep neural networks assisted with global optimization-based regression methods

Understanding the distribution of hydrogeological properties of the aquifers is crucial for sustainable groundwater resource development. This research explores the application of deep autoencoder neural networks (AE-NN), assisted with global optimization methods for estimating hydrogeological parameters in the Quaternary aquifer system in the Debrecen area, Hungary. Traditional methods for estimating aquifer parameters typically depend on field experiments and laboratory analyses, which are both costly and time-consuming, and often fail to account for the heterogeneity of groundwater formations. In this study, deep AE-NN models are trained to extract latent space (LS) representations that capture key features from the available well logs, including spontaneous potential (SP), natural gamma ray (NGR), shallow resistivity (RS), and deep resistivity (RD). The LS log is then correlated with shale volume and hydraulic conductivity, as determined by the Larionov and Csókás methods, respectively. Regression analysis revealed a Gaussian relationship between the LS log and shale volume and a negative nonlinear relationship with hydraulic conductivity. Global optimization methods, including simulated annealing (SA) and particle swarm optimization (PSO), were used to refine the regression parameters, enhancing the predictive capabilities of the models. The results demonstrated that AE-NN assisted with global optimization methods can be effectively used to estimate shale volume and hydraulic conductivity, proposing a novel and independent approach for estimating hydrogeological parameters critical to groundwater flow and contaminant transport modeling.

Identification of the low resistivity-low contrast (LRLC) gas-bearing pay zones in Shaly sand reservoirs using acoustic data: a case study from the Messinian Abu Madi formation, onshore Nile Delta, Egypt

AbstractDetection of the low resistivity-low contrast (LRLC) reservoirs is among the main challenges in the oil industry. In this concern, the LRLC pay zones of the Upper Messinian Abu Madi clastic reservoirs in the onshore Nile Delta Gas fields became a main challenge for significant exploration. This type of reservoirs, including low resistivity-low contrast zones and thin-bedded intervals, are often overlooked using the conventional petrophysical evaluation techniques, especially in the wildcat exploratory wells or highly agitated shoreline depositional environments like the Nile Delta of Egypt. These hidden low contrast reservoirs are generally challenging due to the presence of many shale intercalations/laminations and/or due to increasing the shale volume represented in the form of dispersed distribution, and the dominance of conductive clay minerals. Therefore, in this study, the expected high resistivity values of the gas-bearing reservoir intervals of the Abu Madi Formation in the onshore Begonia gas Field, as a typical case study of the LRLC reservoirs, are masked due to the relatively high shale conductivity, particularly when the thickness of these intervals is less than the vertical resolution of the utilized conventional resistivity log. To verify the LRLC phenomena of the Begonia gas Field, the obtained data was compared to the South Abu El Naga gas Field as a normal case study with a relatively high resistivity gas-bearing pay zone. To overcome the impact of the conductive clay mineral content and identify these hidden low resistivity reservoir intervals, it is necessary to integrate the conventional logging data (gamma-ray, shallow and deep resistivity, density, and neutron) with the acoustic log data including shear and compressional sonic data. In this way, a useful relationship can be established enabling the detection of these hidden LRLC reservoir intervals. This integration is based on the principle that shear waves are not influenced by the fluids types, whereas the compressional sonic waves are influenced by the reservoir fluids. However, to effectively investigate these concealed LRLC reservoir intervals, which can boost production and increase the potential reserves, it is essential to have a low water cut value. The present study represents introduces an efficient workflow, which can be extended to other similar LRLC pay zones in the Nile Delta and northeast Africa. It is also extendible to the LRLC reservoirs in similar deltaic systems having conductive minerals-bearing reservoirs or thin beds.

Multicriteria evaluations for sand production potentials: a case study from a producing oil field in the Niger Delta Basin (Nigeria)

Geomechanical evaluation of three wells in an onshore Niger Delta Oil Field in which some reservoirs have histories of free water production was carried out to predict their potential for sand production. The mechanical characteristics of the reservoirs, such as the Poisson ratio (v), shear modulus (G), elastic modulus (E), bulk modulus (Kb), and bulk compressibility, were calculated using petrophysical parameters such as s-velocity (Vs), p-velocity (Vp), gamma ray index (IGR), the volume of shale (Vsh), porosity (), and pseudo factor (q) derived from wireline logs (Cb). Five geomechanical techniques—porosity, acoustic wave travel time, sand production index, Schlumberger sand production index, and shear modulus to bulk compressibility ratio (G/Cb) were used to forecast the potential for sand production in the reservoirs. The porosity values varied from 14 to 27%, which is below the threshold value of 30% for sand production. The acoustic wave travel time ranged from 81.59 to 89.91s/ft, which is below the threshold value of 104s/ft for sand production. The threshold value for the sand production index was &lt; 2.9 ×106psi. The values for the sand production index fell between 11x 106psi and 12.4 x 106psi, which is below the limits for the onset of sanding. The G/Cb values in the reservoirs across the three wells fell between 1.15 x 1012psi2 and 1.43 x 1012psi2 while the threshold value for the Schlumberger sand production index fell between 1.15 x 1012psi2 and 1.43 x 1012psi2. Only the Schlumberger criterion predicted the potential for likely sand production.

Integrated seismic, petrophysical, and geochemical studies for evaluating the petroleum system of the Upper Bahariya-Abu Roash G sequence in the Karama Field, Abu Gharadig Basin, North Western Desert, Egypt

The main aim of this study is to delineate the hydrocarbon potential and evaluate the petroleum system elements of the Cenomanian Abu Roash G (AR/G) and the Upper Bahariya Members in the Karama Field. It lies at the southeast borders of the Abu Gharadig Basin, a well-known basin in the W.D. to the NE of Africa. We accomplish this study by analyzing a total of thirty 2D seismic profiles, a complete data set of well logs for five wells, and their geochemical data. The workflow starts with illustrating the dominant subsurface structural features, defining the main potential reservoirs and their parameters, and checking the maturity of the probable source rocks. The seismic interpretation indicated that the research area had been influenced by a NE-SW anticlinal structure accompanied by a set of WNW-ESE and NW-SE normal faults that are controlled by the positive compression inversion process that dominated during the Late Cretaceous. Analyzing and processing the well log data sets suggest that the reservoirs of the Abu Roash G (AR/G) and the Upper Bahariya Members are characterized by poor to good reservoir settings with net-pay thickness reaching up to 13–50 feet in the different wells (av. Effective porosity (∅eff) = 17.7 % and 15.6% for the AR/G and the Upper Bahariya Members, av. Shale volume (Vsh) = 17.4 % and 13.6 %, av. Water saturation (Sw) = 38.9 % and 39.8 %, while av. Hydrocarbon saturation values (So) = 60.2 % and 61.1%, respectively). The geochemical and maturity analyses assisted in determining the potential mature source rocks of the Jurassic Khatatba Shale (TOC = 0.70–5.67%; S1+S2 = 0.43–5.97 mg/g, Ro = 0.54–1.06 %) with some contribution from the Cretaceous sources (Alam El-Bueib and Bahariya Formations). Studying elements of the petroleum regime of the Karama Field indicates that the trapped hydrocarbons are structurally controlled by three-way dip closures, horst blocks, sealing faults, and vertical sealing by impervious shale and limestone beds. This case study could be applied to similar analogs in other oil fields in the Egyptian Western Desert to delineate their hydrocarbon potential and structural setting.

PNN Enhanced Seismic Inversion for Porosity Modeling and Delineating the Potential Heterogeneous Gas Sands via Comparative Inversion Analysis in the Lower Indus Basin

Seismic inversion has been in use for the last two decades to measure inverted impedances using an integrated data set approach. This research focuses on the application of multi-attribute seismic inversion and the geostatistical probabilistic neural network (PNN) approach for determining rock properties and litho-fluid classification in the Mehar-Mazarani Field of the Lower Indus Basin (LIB), Pakistan. The study compares five different inversion techniques, including model-based inversion (MBI), colored inversion (CI), linear sparse spike inversion (LSSI), band-limited inversion (BLI), and maximum likelihood sparse spike inversion (MLSSI). The inverted outputs, such as acoustic P-impedance (Zp), density (ρ), porosity (φ), and shale volume (Vsh), were analyzed in Paleocene and Cretaceous geological complex reservoirs to identify gas-bearing zones. The results indicated the existence of gas between 1630 and 1700 ms (ms) and corresponding depth ranges from approximately 3200 m up to 4200 m with varying thickness. Amongst the inversion techniques, MBI demonstrated greater accuracy, with inverted density volumes showing a strong correlation coefficient of 0.98 and the lowest root mean square error (RMSE) and relative error of 0.10 m/s * g/cc. A geostatistical PNN approach was employed to estimate variations in Vsh and φ within the sand reservoir. MBI again yielded more reliable results, with a strong correlation between the measured and inverted attributes. High φ and low Vsh were observed in predetermined low-impedance zones. Overall, MBI is proven to be the most accurate and reliable technique, providing clear identification of the gas occurrence. This research highlights the effectiveness of seismic inversion, particularly the application of MBI, in determining rock properties and identifying gas-bearing zones within the Mehar-Mazarani gas field.

Microfacies Analysis and Evolution of Porosity of the Albian-Early Cenomanian Mauddud Formation from Selected Wells in Ratawi Oilfield, Southern Iraq

Mauddud Formation (Albian stage-the Early Cretaceous) is an important oil reservoir in Ratawi field of southern Iraq. Four wells, R T-2, R T-3, R T-6, and R T-7, located 70 km northwest of Basra, were selected to study microfacies properties and petrophysical associations with the probability of oil production. Seventy-seven core samples are collected, and thin sections for petrographic analysis. The self-potential, Gamma-ray, resistivity, and porosity logs are used to determine the top and bottom of the Mauddud Formation. Water saturation of the invaded and uninvaded zones, shale volume, and porosity were calculated. The study area results showed that the quantity of shale is less than 15% for most of the wells, and the dominant porosity is the secondary porosity. In contrast, the primary porosity is low in all study wells, and the formation contains varying proportions of producing hydrocarbons. The results suggest the formation comprises light-colored dolomitized lime and pseudo-oolitic white limestone with green to blue-gray shale. The petrographic analyses of 65 thin sections of the Mauddud Formation reveal that most skeletal grains are shallow marine-derived faunas, while non-skeletal grains include peloids and ooids. The facies analysis showed that the Mauddud Formation was deposited within different sedimentary environments ranging from deep to very shallow environments, which was represented by a large variation in Five microfacies and ten submicrofacies, the microfacies "Mudstone, wackestone, packstone, grainstone, and Rudstone "submicrofacies" Peloidal wackestone to packstone, Bioclastic wackestone to packstone, Miliolids wackestone to packstone,Orbitolina wackestone, Peloidal packstone to grainstone, Orbitolina packstone, Mudstone to wackestone,Bioclastic wackestone, Miliolids and Bioclastic wackestone to packstone, Bioclastic packstone, and Peloidai grainstone". This variance suggested that the formation might be deposited within the carbonate platform's variety of environment, such as "deep sea, restricted, shallow open marine, mid-ramp, rudist biostrome, and shoal." Seven different kinds of pores have been found in the carbonate sideman of the Formation: Interparticle, Intraparticle, moldic, Vuggy and fracture.

Formation Evaluation and Petrophysical Analysis of Well Logging Data: an Example From Matruh-Shushan Basin, North Western Desert, Egypt

Petrophysical evaluation of well logging data is crucial for exploring and improving oil and gas reservoirs. This involves obtaining reliable information about the rocks and fluids in the reservoir to estimate reserves and make informed decisions about drilling, production, and development strategies. In this study, data from six wells in the Matruh-Shushan Basin were evaluated using Log Quality Control procedures. Two zones of interest, Lower and Upper Safa members, were identified, and quantitative interpretation was conducted to determine the most effective parameters defining reservoir quality: Shale Volume, Effective Porosity, and Water Saturation. Results were positive, with promising net pay for both reservoirs. Numerical models and statistical methods were used to account for data uncertainties and provide reliable estimates of reservoir properties. The study highlights the significance of correct interpretation in successfully exploring and producing hydrocarbons.

Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses

The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.

Seismic Inversion Techniques and Attribute Analysis for Accurate Well Placement in Offshore Niger Delta Basin, Nigeria

Before this study, simple methods like seismic attribute analysis have often been used for reservoir characterization with successes however, there is still the need to reduce exploration uncertainty to a negligible level and boost investors’ confidence. This study integrated seismic inversion with seismic attribute analysis to better characterize the reservoirs in MTW Field in deep-offshore Niger Delta Basin. Five (5) wells with complete suite of petrophysical logs, three-Dimensional (3-D) seismic data, checkshot and other well information were used. The well data were thoroughly quality checked, reservoirs were litho-stratigraphically delineated and used for petrophysical analysis across the wells. This was followed by seismic-to- well-tie, seismic interpretation, and seismic attribute analysis (Root Mean Square-RMS) generated using depth surface maps. 3-D static reservoir model and volumetric evaluation were carried out. Petrophysical properties were derived and distributed across the 3-D static model using sequential gaussian simulation algorithm to ascertain shale volume spread across the model. To improve the seismic resolution and reduce interpretation uncertainty at greater depth, model- based post-stack seismic inversion was performed to obtain acoustic impedance cube. Litho-stratigraphic and petrophysical analysis result revealed five reservoir sands (A, B, C, D, and E). Reservoir-A was seen to be more viable with a thickness of 13.42 m, high effective porosity of 27%, permeability of 3187.53 mD, low water saturation of 34% and low shale volume of 11% which are indication good reservoir quality and producibility. The seismic interpretation revealed thirty-one (31) growth and antithetic faults oriented in the NE-SW and NW-SE directions, respectively. The RMS result revealed high amplitude reflectivity which is a measure of zone of interest. Based on this, seven (7) prospects and three (3) leads were identified. The seismic inversion result shows a high level of accuracy with a correlation coefficient of 0.997; 0.997; 0.995; and 0.996 in MTW-001, MTW-003ST1, MTW-004ST1 and MTW-005 wells, respectively. The acoustic impedance successfully resolved and improved on the resolution of the seismic stacking velocity especially at reservoir layers and at depth deeper than 3600 ms. Acoustic impedance as a layer property has improved on the lateral and vertical resolutions of the data beyond what the usual seismic interval velocity could image thus, validating some of the prospects and leads identified in this study. This demonstrated that uncertainty can be reduced by a blend of RMS and seismic inversion in identifying reservoir for accurate placement of wells. It is therefore recommended that E and P operators should adopt the technique in their future hydrocarbon exploration endeavor in frontier and matured basins.

Petrophysical Characteristics of Mauddud Formation in Selected Wells of Ratawi Oilfield, Southern Iraq

The Mauddud Formation is the most widespread Lower Cretaceous formation in Iraq, deposited along the NE margin of the Arabain Palte. The formation is widely distributed, covering nearly the entire territory of Stable and Unstable Shelf units. The study area is located in the Zubair subzone of the Mesopotamian zone within the Stable Shelf unit, approximately 70 km northwest of Basrah in southern Iraq. The main goal of this study is to evaluate the petrophysical characteristics of Mauddud Formation in the five wells (Ratawi-2, Ratawi-4, Ratawi-5, Ratawi-17, and Ratawi-19) in the Ratawi oilfield, southern Iraq. Open hole log analysis was utilized, and a series of calculations were applied to evaluate the reservoir properties, such as porosity, water saturation, and volume shale, that control the reservoir quality. The N-D cross plot diagram shows that limestone is the dominant lithology, and few shale contents is present in the upper and lower parts of the formation, while it is noticed that the volume of clay is constant throughout the formation in most of the wells, indicating that the formation is clean. Seven zones (A to G) have been identified and evaluated, depending mainly on full set logs to determine the most productive ones. Zones B, D, and F are classified as good reservoir zones with an average porosity of 21% and water saturation of 25%. A and C zones show reservoir and non-reservoir zones with porosity of 10% and water saturation of 40%. Finally, the remaining zones represented by E and G are classified as non-reservoir zones with a very low porosity of less than 4% and fully water-saturated.

Petrophysical Evaluation of Arkoses Reservoirs Based on Well Logs and Plug Samples: A Case Study From Alagamar Formation, Southeastern Portion of Onshore Potiguar Basin, Brazil

The Potiguar Basin is a sedimentary basin located in northeastern Brazil. It covers about 48,000 km² and extends from onshore to offshore. The onshore basin is thought to have formed during the Late Cretaceous, as a result of the opening of the Equatorial South Atlantic Ocean, filled with a thick sequence of sedimentary rocks, including sandstones, shales, and limestones, which were deposited in a variety of processes, including marine, deltaic, and fluvial. The study area is in the southern portion of the basin and the reservoir is composed of arkose sandstones deposited by alluvial fan and fluvial systems of the Upanema Member of the Alagamar Formation, which belongs to the post-rift phase of the Potiguar Basin. Recently, new drilling campaigns revealed a reservoir heterogeneity in these deposits, which requested a new petrophysical approach. Using conventional well logs and petrophysical laboratory analysis of plug samples, this study evaluated the best way to calculate the effective porosity, and shale volume and to understand the stratigraphic controls in the distribution of these properties. Three reservoir zones were mapped: the basal one, Zone 3, has disconnected sand bodies, low porosity, and high shale content; Zone 2 has better petrophysical properties, lateral distribution, and connectivity between the fans and Zone 1 is the better reservoir zone with larger sand bodies, higher porosity values, and well-connected fans.

Petrophysical Parameters and Electrofacies Models of the Itararé Group Applying Multi-Resolution Graph-Based Clustering Method, Paraná Basin

Volume shale (Vsh) and effective porosity (Φe) were calculated and partially applied as petrophysical input parameters to generate electrofacies models using the Multi-Resolution Graph-Based Clustering method in sedimentary successions of the Itararé Group. The petrophysical parameters and electrofacies models were determined from geophysical data from two wells located in the eastern portion of the Paraná Basin. The stratigraphic intervals in each well (analogues of hydrocarbon reservoirs) allowed petrophysical analysis and the determination of electrofacies models based on gamma ray profiles, apparent density and neutron porosity, together with lithological data. The petrophysical parameters were calculated by different procedures, and the effective porosity results were applied as input parameters for electrofacies modeling. The electrofacies models were correlated to lithological data and patterns of gamma ray profiles and apparent density, as well as different types of porosity. The generated models provide differences related to the type of porosity, the method applied to calculate the effective porosity and present probable relationships with the lithological units of the wells.

Sedimentological and petrophysical characterization of the Bokabil Formation in the Surma Basin for CO2 storage capacity estimation

Large-scale geological sequestration of CO2 is one of the most effective strategies to limit global warming to below 2 °C, as recommended by the Intergovernmental Panel on Climate Change (IPCC). Therefore, identifying and characterizing high-quality storage units is crucial. The Surma Basin, with its four-way dip closed structures, high-quality reservoirs, and thick regional cap rocks, is an ideal location for CO2 storage. This study focuses on the Bokabil Formation, the most prominent reservoir unit in the Surma Basin. Detailed petrographic, petrophysical, XRD, and SEM analyses, along with mapping, have been conducted to evaluate the properties of the reservoir and cap rock within this formation. The Upper Bokabil Sandstone in the Surma Basin ranges from 270 to 350 m in thickness and consists of fine- to medium-grained subarkosic sandstones composed of 70–85% quartz and 5–12% feldspar, with good pore connectivity. Petrophysical analysis of data from four gas fields indicates that this unit has a total porosity of 21–27.4% and a low shale volume of 15–27%. Cross plots and outcrop observations suggest that most of the shales are laminated within the reservoir. The regional cap rock, known as the Upper Marine Shale (UMS), ranges in thickness from 40 to 190 m and contains 10–40 nm nano-type pores. A higher proportion of ductile materials with a significant percentage of quartz in the UMS indicates higher capillary entry pressures, enhancing its capacity to hold CO2. Using the CSLF method with a 6% cut-off of the available pore volume, it is estimated that 103 Mt, 110 Mt, 205 Mt, and 164 Mt of CO2 can be effectively stored in the Sylhet, Kailashtila, Habiganj, and Fenchuganj structures, respectively. Due to the shallow depth of the storage unit and the thick cap rock, the southern Surma Basin is the optimal location for CO2 injection.

Seismic coloured inversion to explore the hydrocarbon prospectivity of a field in the Upper Assam basin

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.

Prediction of reservoir properties and fluids using rock physics techniques in the Rio Del Rey Basin, Cameroon

The application of rock physics modeling has been a breakthrough in oil and gas industry and has greatly managed exploration and interpretation risk. In the Rio del Rey Basin, the rock physics method was used to ascertain the reservoir's characteristics and relate them to the elastic characteristics. Using conventional techniques to connect to the elastic properties and assess various rock physics diagnostics, the estimated petrophysical parameters were water saturations, porosity, and shale volume. By connecting the saturated bulk modulus to its porosity, the bulk modulus of the porous frame, the bulk modulus of the mineral matrix, and the bulk modulus of the pore filling fluids, the Gassmann fluid replacement modeling was used to simulate various fluid scenarios. Finally, an evaluation was conducted on rock physics boundaries and cement models. The reservoirs are rated as extremely good based on the results. The rock physics model generated showed the friable sand model is a suitable model for the said basin and the rock physics bounds that were evaluated indicated that the sediments are deposited below the critical porosity and less compacted thereby depicting a soft sand model. Conventional petrophysical study would not be able to reveal the clustering of the gas sands from the brine sand and the shale zone in connection to the geologic trend as demonstrated by the rock physics template. The anticipated model will be useful to extrapolate the study to other sedimentary basins in Cameroon and estimate porosity from the impedance acquired from seismic data throughout the basin.