Explore the vast range of titles available.

hailaer oilfield belongs to low permeability fault-block oilfield, some blocks effectively injection Wells after fracturing is still hard, lead to low formation pressure, the late refracturing effect is poor, single and average increased under 400 t oil and to explore effective fracturing technology in the low permeability elastic exploration area, hailaer oilfield since 2011, in fissured budate reservoir, according to the characteristics of the reservoir Large-scale clear water fracture network fracturing tests have been carried out, and better stimulation effect has been achieved. The tests have guiding significance for the effective development of low efficiency and difficult to recover reservoirs in Hailaer oilfield.

See the retraction notice E3S Web of Conferences 538 , 00001 (2024), https://doi.org/10.1051/e3sconf/202453800001

This study aims to integrate petrophysical characterization and reservoir evaluation for optimizing field development. The focus is on the Kafr Elsheikh formation, using iso-parametric maps to analyze key reservoir parameters such as effective porosity, shale content, net-pay thickness, permeability, hydrocarbon saturation, and water saturation across lateral sections. Petrophysical characterization is essential for understanding the reservoir quality and productivity potential. The study evaluates four wells—Sapphire 1, Sapphire-Da, Sapphire-Deep 1, and Sapphire-Dh—using well logs, including gamma ray, caliper, density, neutron, and resistivity, recorded in Las files. These wells are crucial for assessing the reservoir potential and development path of the Sapphire Field. Findings reveal that the Kafr Elsheikh formation has significant reservoir potential, with effective porosity ranging from 14 to 34%, water saturation between 15% and 45%, gas saturation from 55 to 85%, and net-pay thickness from 0.46 m to 23.8 m. Lithological analysis shows a composition of sandstone and shale within the formation. The developmental trajectory of Sapphire Field indicates increases in effective porosity and hydrocarbon saturation towards the central and northwest-southeast directions. Sapphire Da is identified as the most promising well, with 85% saturation, 29% effective porosity, and a net-pay thickness of 14.04 m. The study underscores the hydrocarbon reserves in the Kafr Elsheikh formation and advocates for further exploration and development wells to enhance productivity. Insights from iso-parametric maps are vital for future exploration and development within the Sapphire Field.

Metamorphic buried hills are characterized as fractured reservoirs with immense potential for hydrocarbon exploration and exploitation. Identifying their effective reservoirs is crucial for prioritizing exploration and development efforts. However, current methods are inadequate for such reservoirs. In this study, we established a new evaluation method, the metamorphic reservoir quality index (MRQI), based on analyses of wallrock cores, cuttings, well logs, and test data in the Bozhong (BZ) 19-6 area. The MRQI method integrates three main control factors for the formation of metamorphic buried hill reservoirs, namely lithology, tectonism, and weathering. Our results indicate that exploratory wells in the BZ19-6 area have MRQI values ranging from 29.91 to 86.47, with average of 56.45, showcasing the wide distribution of metamorphic rocks with moderate reservoir quality. We also observed a significant increasing trend between fracture development and MRQI values, suggesting that MRQI can effectively characterize reservoir development. Moreover, individual well production displays an exponentially increasing trend with higher MRQI, with a clear turning point at MRQI of 65, representing the lower limit of an effective reservoir. Finally, we applied the MRQI method to classify the reservoir through depth in two exploration wells, demonstrating its effectiveness. The MRQI method enables quick and effective decision-making on exploratory and developmental projects in metamorphic buried hills. Hence, this method provides a valuable tool for reservoir management and enhancing the economic benefits of exploration and exploitation in such reservoirs.

Reservoir characterization, crucial for oilfield development, aims to unravel intricate non-linear relationships within real-world data. Conventional methods, rooted in simplistic theories, often lead to uncertainties and inaccuracies in workflows. Leveraging the power of deep learning, this study introduces a pioneering approach: a hybrid neural network model merging convolutional and Long Short-Term Memory (LSTM) RNN layers. Focused on effective porosity modeling for the Ghar Member of the Asmari Formation in western Iran, the study utilizes post-stack seismic data and well-log information. By effectively deciphering spatio-temporal information within the data, our methodology allows for spatially aware predictions of effective porosity values, a capability not addressed by previous studies. The hybrid neural network model predicts effective porosity values for the entire reservoir, creating a 3D grid of porosity. It leverages CNN and RNN layers to decipher spatio-temporal information within the data, thereby enabling the model to make spatially aware predictions. The model achieved a mean squared error (MSE) of 0.005, generating clear 3D porosity models with greater detail compared to traditional machine learning and geostatistical methods. This innovative methodology represents a step forward in reservoir characterization, offering improved precision and efficiency. It holds promise for advancing oilfield development practices in the future.

This study integrated three-dimensional (3D) structural and petrophysical models to establish the reservoir characteristics of the Mangahewa Formation within the Pohokura Gas-Condensate Field. The 3D structural model, in which 3 horizons and 51 faults were interpreted, was developed using an algorithm for volume-based modeling. The complex structural mechanism was observed as compressional and extensional stresses resulting in steeply dipping normal and reverse faults. The fault throw was estimated to be up to 85 m, and 33% of the faults had throws of less than 10 m. This explains the fault growth system as small, younger faults have merged to develop larger faults. Well log analysis was used to evaluate important petrophysical parameters such as effective porosity, net-to-gross ratio, shale volume, and water and hydrocarbon saturation. After applying a cutoff, the estimated values for effective porosity, net-to-gross ratio, shale volume, and water and hydrocarbon saturation were 12–18%, 13–31%, 13–26%, 6–22%, and 78–94%, respectively. The estimated values were then incorporated into the grid cells to design 3D petrophysical modeling using the algorithm for sequential Gaussian simulation. The structural model indicated effective trapping and the presence of a conduit mechanism for hydrocarbons. The well log analysis identified significant effective porosities containing substantial hydrocarbon saturation, whereas the petrophysical models showed very good dissemination of the petrophysical parameters. From these models, which also incorporate the gas–water contact, proposed drilling sites for future exploration and well development were proposed. The results characterize the Mangahewa Formation as a good reservoir within the Pohokura Gas-Condensate Field.

Exploration of the heterogeneous sandstone reservoirs presents a significant opportunity within the Nile Delta Basin. This study uses the well log, core, and petrographical data to describe the different rock types and characterizes the heterogenous sandstone of the Late Miocene Messinian Abu Madi reservoir as one of the main prolific reservoirs in the South Abu El Naga Gas Field in the Nile Delta. However, accurate assessment of the potential of these complex and heterogeneous sandstone reservoirs requires a meticulous approach. The available data was imported from four wells: SAEN-2, SAEN-4, SAEN-6, and SAEN-9. A total of 35 core plugs, which were derived from two cored intervals in the SAEN-2 well, were used in a well-integrated workflow for reservoir characterization, facies analysis, and rock typing. Core analysis (grain density ‘ρ g ’, helium porosity ‘∅ He ’, horizontal and vertical permeabilities ‘k H & k V ’, and water saturation ‘Sw’) and well log data (caliper, gamma-ray, spontaneous potential, PEF, density, neutron, and resistivity logs) provided crucial insights into the lithology, pore systems, and textures. This information allowed us to define the dominant microfacies types as quartz arenite, feldspathic arenite, quartz wacke/wacke, feldspathic wacke, and subfeldspathic wacke. With the core data, it was also possible to estimate the reservoir quality index (RQI), flow zone indicator (FZI), and the effective pore radius (R 35 ) from core data, while the net pay thickness, the effective porosity, the shale volume (V sh ), and the water saturation (Sw) from the well log data. It also enabled the identification of the potential zones of the gas-bearing reservoirs. Hydraulic flow units (HFUs) were established using well logs and core data. These units represent zones with similar fluid flow properties, facilitating the prediction of gas deliverability. Additionally, the flow zone indicator (FZI) that derived from the well logs further characterized the flow regime within the reservoir. Sedimentological studies, including thin section petrography, XRD, and SEM, complemented with the well log interpretation. This integrated workflow provided a comprehensive perspective of the reservoir, including pore structures, mineral composition, and textures. The Abu Madi Formation in the SAEN-9 well, to the northeast of the field, has the lowest net pay (7.3 m), while the SAEN-2 well, in the center of the field, has the highest net pay thickness (16.6 m). The core studies indicate that SAEN samples could be divided into four reservoir rock types (RRTs). The RRT1 has the lowest reservoir quality (0.12 ≤ ∅ He  ≤ 0.26, 2.4 ≤ k H  ≤ 429 mD, 54.9 ≤ Sw ≤ 70.5%, 0.14 ≤ RQI ≤ 1.22 μm, 0.82 ≤ FZI ≤ 3.863 μm, and 1.055 ≤ R 35  ≤ 11.41 μm), while the RRT4 has the best reservoir quality (0.25 ≤ ∅ He  ≤ 0.28, 2680 ≤ k H  ≤ 4893 mD, 45.4 ≤ Sw ≤ 55.3%, 3.24 ≤ RQI ≤ 4.13 μm, 9.72 ≤ FZI ≤ 10.59 μm, and 34.668 ≤ R 35  ≤ 44.78 μm). This study demonstrates the effectiveness of an integrated approach in comprehensively assessing the potential gas-bearing reservoirs and defining their quality in the Abu Madi Formation in the Nile Delta, which is characterized by very good reservoir quality (net pay thickness = 7.3–16.6 m, av. porosity = 23.3–30.35%, and av. water saturation = 31.7–64.0% for the various wells). The findings contribute significantly to optimizing exploration and development strategies for gas-bearing hydrocarbon resources in the Nile Delta Basin, especially for the Abu Madi reservoir.

An essential greenhouse gas effect mitigation technology is carbon capture, utilization and storage, with carbon dioxide (CO 2 ) injection into underground geological formations as a core of carbon sequestration. Developing a robust 3D static model of the formation of interest for CO 2 storage is paramount to deduce its facies changes and petrophysical properties. This study investigates a depleted oilfield reservoir within the Bredasdorp Basin, offshore South Africa. It is a sandstone reservoir with effective porosity mean of 13.92% and dominant permeability values of 100–560 mD (1 mD = 9.869233 × 10 –16 m 2 ). The petrophysical properties are facies controlled, as the southwestern area with siltstone and shale facies has reduced porosity and permeability. The volume of shale model shows that the reservoir is composed of clean sands, and water saturation is 10–90%, hence suitable for CO 2 storage based on petrophysical characteristics. Static storage capacity of the reservoir as virgin aquifer and virgin oilfield estimates sequestration of 0.71 Mt (million tons) and 1.62 Mt of CO 2 , respectively. Sensitivity studies showed reservoir depletion at bubble point pressure increased storage capacity more than twice the depletion at initial reservoir pressure. Reservoir pressure below bubble point with the presence of gas cap also increased storage capacity markedly.

A complex structural geology generally leads to significant consequences for hydrocarbon reservoir exploration. Despite many existing wells in the Kadanwari field, Middle Indus Basin (MIB), Pakistan, the depositional environment of the early Cretaceous stratigraphic sequence is still poorly understood, and this has implications for regional geology as well as economic significance. To improve our understanding of the depositional environment of complex heterogeneous reservoirs and their associated 3D stratigraphic architecture, the spatial distribution of facies and properties, and the hydrocarbon prospects, a new methodology of three-dimensional structural modeling (3D SM) and joint geophysical characterization (JGC) is introduced in this research using 3D seismic and well logs data. 3D SM reveals that the field in question experienced multiple stages of complex deformation dominated by an NW to SW normal fault system, high relief horsts, and half-graben and graben structures. Moreover, 3D SM and fault system models (FSMs) show that the middle part of the sequence underwent greater deformation compared to the areas surrounding the major faults, with predominant one oriented S30°–45° E and N25°–35° W; with the azimuth at 148°–170° and 318°–345°; and with the minimum (28°), mean (62°), and maximum (90°) dip angles. The applied variance edge attribute better portrays the inconsistencies in the seismic data associated with faulting, validating seismic interpretation. The high amplitude and loss of frequency anomalies of the sweetness and root mean square (RMS) attributes indicate gas-saturated sand. In contrast, the relatively low-amplitude and high-frequency anomalies indicate sandy shale, shale, and pro-delta facies. The petrophysical modeling results show that the E sand interval exhibits high effective porosity (∅eff) and hydrocarbon saturation (Shc) compared to the G sand interval. The average petrophysical properties we identified, such as volume of shale (Vshale), average porosity (∅avg), ∅eff, water saturation (SW), and the Shc of the E sand interval, were 30.5%, 17.4%, 12.2%, 33.2% and, 70.01%, respectively. The findings of this study can help better understand the reservoir’s structural and stratigraphic characteristics, the spatial distribution of associated facies, and petrophysical properties for reliable reservoir characterization.

This study presents a comprehensive petrophysical assessment of the Alam El Bueib 3E (AEB-3E) sandstone reservoir in the Berenice Oil Field, located within the Faghur Basin, Western Desert, Egypt. The main objective is to evaluate reservoir quality, hydrocarbon potential, and lateral continuity to support effective field development strategies. The analysis is based on wireline log data from four wells: Berenice-TD-1X, Berenice-03, Berenice-08, and Berenice-09. Lithological analysis using M–N and RHOB–NPHI crossplots confirms that the reservoir is predominantly composed of clean sandstone, with limited shale and siltstone interbeds. Hydrocarbon-bearing intervals were identified between 11,150 and 11,190 feet based on neutron-density separation, resistivity log responses, and indicators of movable hydrocarbons. Formation water resistivity (Rw = 0.0378 Ω·m) and Archie parameters (a = 1, m = 1.9, n  = 2) were derived from Pickett plot analysis in the Berenice-08 well, providing a basis for water saturation estimation in the absence of core data. The reservoir exhibits low shale content (3–8%), with effective porosity reaching up to 18%, particularly in the southeastern part of the field. Water saturation ranges between 28% and 54%, and the net pay intervals align well with hydrocarbon-bearing zones. Structural mapping and well correlation indicate consistent reservoir thickness, with central thickening influenced by ENE–WSW trending normal faults. Seismic interpretation reveals horst and graben structures that contribute to reservoir compartmentalization. The petroleum system is supported by mature source rocks of the Safa Formation, in addition to effective intraformational and regional seals, which enhance hydrocarbon entrapment. The results of this study contribute to a clearer understanding of the petrophysical and structural characteristics of the AEB-3E reservoir, offering valuable insights for future development and exploration efforts in the region.