Flow Units Research Articles

Single-Factor Comprehensive Reservoir Quality Classification Evaluation-Taking the Hala'alat Mountains at the Northwestern Margin of the Junggar Basin as an Example.

In the process of petroleum geology exploration and development, reservoir quality evaluation is an essential component. However, conventional reservoir quality evaluation methods are no longer able to provide accurate and comprehensive assessments for all types of reservoirs. Therefore, the comprehensive evaluation of reservoir quality using multiple single factors is of significant importance in improving the level of reservoir quality assessment and enhancing the effectiveness of oil and gas exploration techniques. Conventional reservoir quality evaluation methods can assess only the quality of individual reservoir properties, resulting in limited classification outcomes. Taking the Cretaceous formations in the southern margin of the Hala'alat Mountain in the Junggar Basin as the research object, preliminary classification criteria were established based on the principles of formation coefficient, storage coefficient, and flow unit index. Combining experimental data such as core observation, thin-section identification, pore permeability analysis, and scanning electron microscopy, a comprehensive set of reservoir quality classification and evaluation criteria were developed. Furthermore, the corresponding reservoir classification evaluation maps were generated to illustrate the spatial distribution of reservoir quality. The study reveals that the area can be classified into four types of reservoirs, namely, Class I, Class II, Class III, and Class IV, corresponding to the best reservoir, relatively good reservoir, relatively poor reservoir, and poor reservoir, respectively. Among them, the second (K1q2) and third (K1q3) members of the Cretaceous Qingshuihe Formation, as well as the first (K1h1) and third (K1h3) members of the Cretaceous Hutubi Formation, exhibit the best reservoir quality as Class II. On the other hand, the second member of the Cretaceous Hutubi Formation (K1h2) exhibits the best reservoir quality as Class III, with relatively poorer reservoir quality overall. The research findings of this study can provide an important theoretical basis for oil and gas exploration and development in the region.

Rock Typing Approaches for Effective Complex Carbonate Reservoir Characterization

For highly heterogeneous complex carbonate reef reservoirs, rock typing with respect to depositional conditions, secondary processes, and permeability and porosity relationships is a useful tool to improve reservoir characterization, modeling, prediction of reservoir volume properties, and estimation of reserves. A review of various rock typing methods has been carried out. The basic methods of rock typing were applied to a carbonate reservoir as an example. The advantages and disadvantages of the presented methods are described. A rock typing method based on a combination of hydraulic flow units and the R35 method is proposed. Clustering methods for rock typing are used. The optimum clustering method is identified, and for each rock type, the permeability–porosity relationships are built and proposed for use in the geomodelling stage.

Porosity prediction from prestack seismic data via deep learning: incorporating a low-frequency porosity model

Abstract Porosity prediction from seismic data is of considerable importance in reservoir quality assessment, geological model building, and flow unit delineation. Deep learning approaches have demonstrated great potential in reservoir characterization due to their strong feature extraction and nonlinear relationship mapping abilities. However, the reliability of porosity prediction is often compromised by the lack of low-frequency information in bandlimited seismic data. To address this issue, we propose incorporating a low-frequency porosity model based on geostatistical methodology, into the supervised convolutional neural network to predict porosity from prestack seismic angle gather and seismic inversion results. Our study demonstrates that the inclusion of the low-frequency porosity model significantly improves the reliability of porosity predictions in a heterogeneous carbonate reservoir. The low-frequency information can be compensated to enhance the network's capabilities of capturing the background porosity trend. Additionally, the blind well tests validate that considering the low-frequency constraint leads to stronger model prediction and generalization abilities, with the root mean square error of the two blind wells reduced by up to 34%. The incorporation of the low-frequency reservoir model in network training also remarkably enhances the geological continuity of seismic porosity prediction, providing more geologically reasonable results for reservoir characterization.

Permeability Estimation for Upper Shale Member in Southern Iraqi Oil Field Using Machine learning and Hydraulic Flow Units Methods

Permeability estimation in the Upper Shale Member is rather complex due to the heterogeneity. Conventional logs do not provide permeability directly, but the core data does. Core operations and analysis processing are all costly. An alternative method is used by dividing the reservoir rock into groups (rock types) with similar characteristics in porosity and permeability for cored wells. These identified groups for the core wells can be applied to the uncored wells to predict their groups and permeabilities. Four wells were used in this study: one cored well and three uncored wells. Two classification methods of rock types were used; the first is the machine learning method (supervised and unsupervised), a new technics invention, and the second method is the hydraulic flow unit. Four groups were selected by using Machine Learning and hydraulic flow unit methods. A regression equation for each rock type was obtained to predict permeability. Then, establishing a relationship between the results of the core data groups and the logs' responses for the core well is referred to as "correlation," which is training the logs that provide an estimating model. A validation check was completed by comparing the rock type and permeability estimation from the core with the rock type and permeability estimation from the logs, which were highly matched. Finally, The rock type and permeability can be estimated for the uncored wells using only the logs that were learned from the generated training data set for the cored wells. Due to the use of more than one model to predict permeability, it was clear that one was more compatible than the other. The flow zone indicator, a classical method, still has a better rock type and permeability estimation than the new techniques, which use data mining and mathematical algorithms on a clustering basis.

Sedimentological and diagenetic effects on petrophysical characteristics and hydraulic flow units of Zhujiang sandstones in the Pearl River Mouth Basin, south China Sea

The Zhu-Ⅲ sag is a key oil and gas rich basin. The Zhujiang Formation is characterized by strong heterogeneity, a changeable sedimentary environment and complex diagenesis, which presents great challenges in the identification of the reservoir sweet spot. Previous researchers have almost no study on it. Therefore, finding high-quality reservoir units is the top priority. In this study, we focus on classifying and evaluating the reservoir units, finding high-quality units and providing exploration recommendations. We carried out core observations and description, X-ray diffraction, cast thin-section observations, electron microscopy observations and mercury intrusion experiments. We used the normal probability distribution model to divide the hydraulic flow unit into six types and determined their hydraulic flow capacity. We summarized the depositional model of the study area through core observations and well analysis. By combining the data on the hydraulic flow units, pore throat radius, sedimentary background, diagenesis and reservoir physical properties, we classified six rock facies (RFs). We found that there is good correspondence between rock facies, hydraulic flow units and sedimentary environments. The results indicate that the quality of the RF-1, RF-2 and RF-3 reservoirs are good, while the quality of the reservoir in RF-4, RF-5 and RF-6 are poor. We conclude that RF-2 mainly corresponds to oil layers and oil-water layers, which are favourable target layers for exploration. This research is the first time to study the sedimentation and diagenesis and combine them to evaluate the reservoir physical properties and flow units in the South China Sea comprehensively.

Insight from the Noachian-aged fractured crust to the volcanic evolution of Mars: A case study from the Thaumasia graben and Claritas Fossae

Although most of the large volcanic landforms on Mars have been extensively studied, this is not the case for kilometer-sized landforms whose origin remains uncertain and which might provide important insights into the evolution of Martian volcanism. Previously, different populations of small-scale putative scoria cone volcanoes have been described in Tharsis, specifically in areas where the heavily fractured crust of the Noachian- and Hesperian-age escaped Amazonian resurfacing by younger lava flows. Therefore, we decided to explore a region of old fractured crust in Tharsis, Claritas Fossae, to search for signs of local-scale volcanic activity. Here, we present the results of a mapping campaign focused on the morphological and spectral properties of small-scale constructional mounds in the Noachian-age Claritas Fossae region that was affected by Hesperian- to early Amazonian-aged fracturing. By using data from Context Camera (CTX) and High Resolution Imaging Science Experiment (HiRISE), we mapped 39 mounds superimposed on the ancient crust and determined their morphological and morphometrical properties. The majority of the mounds are elongated (WNW- trending) with steep flanks and without associated flow units. The general appearance of studied edifices is consistent with a volcanic origin and their shapes suggest that they have been emplaced by effusion of viscous, volatile poor lavas incapable of significant flow. In addition, a spectral investigation utilizing the data from the Compact Reconnaissance Imaging Spectrometer for Mars (CRISM) reveal that some of the mounds showed evidence for high concentrations of low-calcium pyroxenes (LCP). Based on the relative stratigraphy, we demonstrate that volcanic activity is responsible for their formation and postdates the main N-S-trending fracturing of the Claritas Fossae, suggesting the formation of a volcanic field in the period spanning through the Late Hesperian and the Early Amazonian. However, morphological evidence such as well-preserved volcanic fissures and fresh-appearing slopes of some of the edifices might suggest even younger age. Among the mapped edifices, we found a well-preserved circular-shaped cone with a short-distance flow-like unit spreading from a caldera-like structure that challenges a scenario in which all the edifices are old. Such relatively young ages of volcanic activity combined with LCP-rich compositions might have critical implications for understanding the temporal evolution of magma compositions on Mars. Moreover, the observed shapes and spectral characteristics of the studied edifices appear to be quite different from other volcanic fields of similar geological settings observed so far on Mars. Therefore, we underline the importance of studying old and heavily fractured terrains that escaped later resurfacing by widespread younger lava flows, in order to search for evidence of small-scale volcanism and better understand local Martian magmatic systems.

An interactive graph resource for chemical engineering teaching

Instructors teaching chemical engineering topics have traditionally used graphical methods to explain core concepts and design unit operations. However, with the shift towards online and blended/flexible learning, there is a need to adapt these graphical methods for online use. This paper presents a set of interactive graphs that can be used for fluid flow, separation process, and reaction process unit operations and aims to investigate students' opinions of the interactive graphs and their motivations for using them in their studies. The digital resource developed in the paper is a set of slim single-page applications written in HTML5 & CSS3 with the numerical calculations undertaken in JavaScript (JS). The interactive graphs are embedded into the virtual learning environment (VLE) system Blackboard for two courses, and a paper survey is used to measure students' perceptions towards the interactive graphs and their use of them. The UTAUT2 model is used to analyse the student use of these resources. It is demonstrated that the use of online interactive graphs is popular with the students and the main driving factors are the performance expectancy and the hedonic motivation. Short scaffold questions to help students interact with the graphs are key to their usefulness. Some guidance on the use of interactive graphs is also provided. The interactive graphical resource can be found and used at the Graphical Chemical Engineering Design weblink: https://www.ce.manchester.ac.uk/gced.

The specification of hydraulic units of flow – the key direction for the classification of terrigenous reservoirs (in the context of South-West Kamyshitov field)

The paper considers a classification method of terrigenous reservoirs based on Hydraulic Units definition, introduced by Ameafule et al. in 1993. The typical groups of reservoirs of Jurassic and Cretaceous sediments with the similar properties of the pore volume were identified based on the results of the standard laboratory studies of the core material. The integration of core and geophysical data were carried out in the process of interpretation of the logging data. The defined classification of the rocks allowed conducting the specific prediction of the permeability by whole penetrated section of South-West Kamyshitov field.

Integrating hydraulic flow unit concept and adaptive neuro-fuzzy inference system to accurately estimate permeability in heterogeneous reservoirs: Case study Sif Fatima oilfield, southern Algeria

Formation characteristics are a crucial requirement for reservoir modeling and they need to be constantly updated as new static and/or dynamic reservoir-property details become available. This improves reservoir interpretation while achieving a good history-matching for a better representation of the reservoir. This paper proposes a new method to estimate reservoir permeability in an oil-producing reservoir by applying two distinct cases: partially cored and completely non-cored wellbores. The approach involves the determination of hydraulic-flow units (HFU) using a flow-zone indicator (FZI) distribution to consider the dynamic aspect of the permeability, which strongly influences fluid flow through porous media. The FZI is clustered by normal probability analysis to identify the optimum number of HFU clusters. The estimated reservoir permeability is validated in static and dynamic reservoir models. For an accurate prediction of the FZI over the entire reservoir thickness, an adaptive-neuro-fuzzy-inference system (ANFIS) is developed using conventional well-log variables: (i) gamma-ray (GR), (ii) sonic (DT), (iii) density (RHOB), (iv) deep resistivity (DLL), and (iv) neutron porosity (NPHI) calibrated with the available core data. The static regression parameters root-mean-squared error (RMSE), mean absolute error (MAE), coefficient of determination (R2), and R2adjusted are used to evaluate the performance of the ANFIS model in predicting FZI to determine HFU for estimating reservoir permeability. To validate this approach, a matching quality check of the downhole and reservoir pressure is carried out using a dynamic reservoir simulation model. Historical data collected from wellbore OPW-1 drilled in the Sif Fatima oilfield (Algeria) are used to evaluate the accuracy of the proposed permeability-prediction framework. The ANFIS model can accurately and efficiently predict the FZI exhibiting R2, R2adjusted, RMSE, and MAE of approximately (≈0.981, ≈0.979, ≈0.014, ≈4,600E-08)), (≈0.933, ≈0.891, ≈0.032, ≈1.615E-03), and (≈0.970, ≈0.968, ≈0.018, ≈2.381E-04)) for the training, testing and complete dataset, respectively. When applied to predict reservoir permeability, the Hydraulic Flow Unit concept was able to generate accurate results from the predicted FZI data by applying the modified Kozeny-Carman equation with, R2, RMSE and MAE values of approximately ≈0.9702, ≈0.969, ≈9.604, and ≈4.398, respectively. The calculated permeability was validated successfully at well and field levels. Additionally, it generated more accurate history matches of the well and the reservoir pressure trends than the previous permeability model, and consequently improved the reservoir modelling workflow.

Using core to reduce risk and deliver added business value throughout field life: a carbonate reservoir focus

Abstract The role of the subsurface team is to reduce technical risk and uncertainty associated with profile delivery, for both hydrocarbon production and the injection of water or gases, enabling confident reservoir management and investment decisions. Core is a key resource for delivering this objective, providing the only opportunity to directly observe and measure the reservoir rock. However, it is expensive to acquire and the decision to take new core should be clearly linked to a business objective. A combination of depositional and diagenetic factors can result in carbonate reservoirs being highly heterogeneous, making them a challenge to find and develop. Core studies can significantly improve understanding of the controls on heterogeneity and its distribution within the subsurface, but to maximize value, they should be fully integrated with wireline logs, seismic and production or test data to predict likely reservoir behaviour. For example, thin (<1 m) high or low permeability zones can dominate production yet remain very subtle or undetectable in wireline log or seismic data alone. During exploration and appraisal, sufficient data and knowledge are required to enable appraise/develop or walk-away decisions. Appropriate geological description of core material helps to establish original volumes in place, net-to-gross, depositional setting, age, reservoir architecture and large-scale flow zones. Core material can also help establish other key reservoir parameters such as saturation, reservoir fluids, seismic rock properties and geomechanical properties as well as influence decisions such as well design, development strategy and facility requirements. As a field is developed and production matures, reservoir behaviour may change and detail of the sedimentology, structure, diagenesis, baffles and thin heterolithic permeability zones may become more important. In carbonate reservoirs, this often requires the integration of existing legacy core or new core material and targeted surveillance data, such as injection and production logging tool (ILT/PLT) or saturation logs, to understand the stratigraphic, depositional and diagenetic controls on flow units and improve predictive capability. Moving a reservoir from natural depletion onto waterflood or enhanced oil recovery (EOR) may need more advanced core-based data from core flood experiments to deliver maximum value from the reservoir. New core material, or detailed review and new sampling of existing or analogue legacy core, may be required to understand complex rock–fluid interactions and the value that waterflood or EOR could bring to a development. To maximize the value and insights gained from core, it is essential to use it throughout a field's life. High quality description and a well-considered sampling regime should be carried out at the earliest opportunity to provide baseline data. However, periodically revisiting the core enables the entire subsurface team to keep testing hypotheses and refreshing models. Where there is no core material available in the field, analogue field core can be especially useful both to narrow uncertainty and explore possible alternative models. A multi-disciplinary approach integrating new data with core observations helps refine and improve predictions and can lead to the identification of significant additional opportunities as reservoir behaviour matures and field development progresses.

Paragenetic controls on CO2-fluid-rock interaction and weakening in a macroporous-dominated sandstone

The injection and storage of anthropogenic CO2 in the subsurface is being deployed as a climate change mitigation tool; however, diagenetic-paragenetic heterogeneity in sandstone reservoirs often contributes to interval specific chemomechanical changes that affect injection and can increase leakage risk. Here, we address reservoir heterogeneities’ impact on chemomechanical changes in a macroporous-dominated lithofacies of Morrow B sandstone, a formation containing several diagenetically-distinct hydraulic facies while undergoing enhanced oil recovery (EOR) and carbon dioxide (CO2) sequestration. We performed three flow-through experiments using a CO2-charged or uncharged formation water combined with four indirect tensile strength tests per post-test sample. We then used the microstructure and paragenetic sequence to understand chemomechanical weakening with key observations as follows: dissolution of carbonates and feldspars changed porosity; increased permeability led to reclassifying each sample in a different hydraulic flow unit; decreased ultrasonic velocity; and did not lead to a loss of tensile strength. Tensile strength maintenance occurred due to the low abundance and minor dissolution of siderite, the stability of quartz, and the relative position of diagenetic ankerite within feldspar. This macroporous-dominated lithofacies is the primary reservoir for the Morrow B Sandstone, and is analogous to other porous sandstone reservoirs. It represents an end-member of a chemomechanically low-risk siliceous CO2 sequestration and CO2-EOR reservoir.

Reservoir quality evaluation of the Narimba Formation in Bass Basin, Australia: Implications from petrophysical analysis, sedimentological features, capillary pressure and wetting fluid saturation

The evaluation of reservoir quality was accomplished on the Late Paleocene to Early Eocene Narimba Formation in Bass Basin, Australia. This study involved combination methods such as petrophysical analysis, petrography and sedimentological studies, reservoir quality and fluid flow units from derivative parameters, and capillary pressure and wetting fluid saturation relationship.Textural and diagenetic features are affecting the reservoir quality. Cementation, compaction, and presence of clay minerals such as kaolinite are found to reduce the quality while dissolution and secondary porosity are noticed to improve it. It is believed that the Narimba Formation is a potential reservoir with a wide range of porosity and permeability. Porosity ranges from 3.1% to 25.4% with a mean of 15.84%, while permeability ranges between 0.01 mD and 510 mD, with a mean of 31.05 mD. Based on the heterogenous lithology, the formation has been categorized into five groups based on permeability variations. Group I showed an excellent to good quality reservoir with coarse grains. The impacts of both textural and diagenetic features improve the reservoir and producing higher reservoir quality index (RQI) and flow zone indicators (FZI) as well as mostly mega pores. The non-wetting fluid migration has the higher possibility to flow in the formation while displacement pressure recorded as zero. Group II showed a fair quality reservoir with lower petrophysical properties in macro pores. The irreducible water saturation is increasing while the textural and digenetic properties are still enhancing the reservoir quality. Group III reflects lower quality reservoir with mostly macro pores and higher displacement pressure. It may indicate smaller grain size and increasing amount of cement and clay minerals. Group IV, and V are interpreted as a poor-quality reservoir that has lower RQI and FZI. The textural and digenetic features are negatively affecting the reservoir and are leading to smaller pore size and pore throat radii (r35) values to be within the range of macro, meso-, micro-, and nano pores. The capillary displacement pressure curves of the three groups show increases reaching the maximum value of 400 psia in group V. Agreement with the classification of permeability, r35 values, and pore type can be used in identifying the quality of reservoir.

Vortex Evolution Behavior in Self-Assembly of Flow Units in Metallic Glasses

Vortex Evolution Behavior in Self-Assembly of Flow Units in Metallic Glasses

Placement and Allocation of Virtual Network Functions: Multi-Dimensional Case

With the gradual transitioning to Network function virtualization (NFV), Internet service providers face the problem of where to introduce NFV in order to make the most benefit of that; here, we measure the benefit by the amount of traffic that can be served in an NFV-enabled network. This problem is non-trivial as it is composed of two challenging subproblems: 1) placement of nodes to support virtual network functions (referred to as VNF-nodes); 2) allocation of the VNF-nodes' resources to network flows. This problem has been studied for the one-dimensional setting, where all network flows require one network function, which requires a unit of resource to process a unit of flow. In this work, we consider the multi-dimensional setting, which introduces new challenges in addition to those of the one-dimensional setting (e.g., NP-hardness and non-submodularity). To address these difficulties, we propose a novel two-level relaxation method that allows us to draw a connection to the sequence submodular theory and utilize the property of sequence submodularity along with the primal-dual technique to design two approximation algorithms. We prove that the proposed algorithms have a non-trivial approximation ratio and perform trace-driven simulations to show the effectiveness of the proposed algorithms.

Integrated Core and Log Data to Determine the Reservoir Flow Unit and Rock Facies for Mishrif Formation in South Eastern Iraq

This work represents study the rock facies and flow unit classification for the Mishrif carbonate reservoir in Buzurgan oil Field, which located n the south eastern Iraq, using wire line logs, core samples and petrophysical data (log porosity and core permeability). Hydraulic flow units were identified using flow zone indicator approach and assessed within each rock type to reach better understanding of the controlling role of pore types and geometry in reservoir quality variations. Additionally, distribution of sedimentary facies and Rock Fabric Number along with porosity and permeability was analyzed in three wells (BU-1, BU-2, and BU-3). The interactive Petrophysics - IP software is used to assess the rock fabric number, flow zones, and reservoir quality index. The Mishrif Formation has four distinct rock types and groups that have been recognized using the approach. The first rock type represents a poor reservoir quality (mud-dominated fabrics) with rock-fabric numbers equals to 2.5-4, the second rock type reveals a moderate reservoir quality (wackestone-Packstone Microfacies), the third rock type depicts a good reservoir quality (grain-dominated packstone) with rock-fabric numbers equals to 1.5-2.5 and 0.5-1.5.

Moveability and Nature of the Reservoir Hydrocarbons in the Lower Miocene Jeribe Formation in X-Oilfield, Northern Iraq

The flow capacity of the Lower Miocene Jeribe Formation was investigated in the two selected wells, A and B, of an oilfield northeast of Tikrit City. The available wireline logs and core test data are adapted for characterizing the reservoir potentiality of the formation. Three Hydraulic Flow Units was identified by calculating the values of the Flow Zone Indicators. Most parts of the formation parts have the lowest flow capacity among the three determined flow types. The Jeribe Formation contains hydrocarbons in various ratios in both wells of the study. The Reservoir Unit RUJ-1 at the upper part of the formation has the highest moveable hydrocarbon saturation, especially in the well A. Most hydrocarbons in the RUJ-3 at the lower part of the formation in both wells are immoveable. The oil-water contact was expected within Dhiban Formation in the well B and was expected to be somewhere in the underlying Dhiban or Euphrates Formations in the well A. The nature of the hydrocarbons at the uppermost few meters of the formation consists of gas or light hydrocarbons and oil at the rest of the formation(residual and moveable oils).

Determination of Reservoir Hydraulic Flow Units and Permeability Estimation Using Flow Zone Indicator Method

Reservoir characterization plays a crucial role in comprehending the distribution of formation properties and fluids within heterogeneous reservoirs. This knowledge is instrumental in constructing an accurate three-dimensional model of the reservoir, facilitating predictions regarding porosity, permeability, and fluid flow distribution. Among the various methods employed for reservoir characterization, the hydraulic flow unit stands out as a widely adopted approach. By effectively subdividing the reservoir into distinct zones, each characterized by unique petrophysical and geological properties, hydraulic flow units enable comprehensive reservoir analysis. The concept of the flow unit is closely tied to the flow zone indicator, a critical parameter that defines the porosity-permeability relationships of each hydraulic flow unit. Additionally, the flow zone indicator method proves valuable in estimating permeability accurately. In this study, we demonstrate the application of the flow zone indicator method to determine hydraulic flow units within the Khasib formation. By analyzing core data and calculating the Rock Quality Index (RQI) and Flow Zone Indicator (∅Z), we differentiate the formation into four hydraulic flow units based on FZI values. Specifically, HFU 1 represents a rock of poor quality, corresponding to compact and chalky limestone. HFU 2 represents intermediate quality, corresponding to argillaceous limestone, while HFU 3 represents good quality, corresponding to porous limestone. Lastly, HFU 4 signifies an excellent reservoir rock quality characterized by vuggy limestone. By establishing a permeability equation that correlates with effective porosity for each rock type, we successfully estimate permeability. Comparing these estimated permeability values with core permeability reveals a strong agreement with a high correlation coefficient of 0.96%. Consequently, the flow zone indicator method effectively classifies the Khasib formation into four distinct hydraulic flow units and provides an accurate and reliable means of determining permeability in the reservoir. The resulting permeability equations can be applied to wells and depth intervals lacking core measurements, further emphasizing the practical utility of the FZI method.

Prediction of Hydraulic Flow Units for Jeribe Reservoir in Jambour Oil Field Applying Flow Zone Indicator Method

The Jeribe reservoir in the Jambour Oil Field is a complex and heterogeneous carbonate reservoir characterized by a wide range of permeability variations. Due to limited availability of core plugs in most wells, it becomes crucial to establish correlations between cored wells and apply them to uncored wells for predicting permeability. In recent years, the Flow Zone Indicator (FZI) approach has gained significant applicability for predicting hydraulic flow units (HFUs) and identifying rock types within the reservoir units. This paper aims to develop a permeability model based on the principles of the Flow Zone Indicator. Analysis of core permeability versus core porosity plot and Reservoir Quality Index (RQI) - Normalized porosity log-log plot reveals the presence of three distinct Hydraulic Flow Units and corresponding rock types within the Jeribe reservoir. These rock types can be identified if known. The reservoir can be divided into three groups of rock types, namely good, moderate, and bad quality. The bad rock type represents a restricted section within the reservoir, while the upper and lower parts predominantly consist of moderate-quality rock types. Conversely, the central section of the reservoir exhibits a good-quality rock type. By utilizing the Flow Zone Indicator principles, this study provides valuable insights into the hydraulic flow behavior and rock types present in the Jeribe reservoir. The proposed permeability model derived from this method can aid in predicting permeability values for uncored wells, contributing to a better understanding of the reservoir's heterogeneity and facilitating reservoir characterization and management decisions.

TRAFFIC FLOW IDENTITY IN THE CONDITIONS OF THE CITY

The movement of a traffic flow along city highways is described by the movement of waves of speed, intensity and density, the equations and characteristics of which allow solving applied problems of traffic control, designing city highways and street-road networks and assessing the quality of existing traffic in cities.
 On the routes (sidewalks) there are flows of people (pedestrian flows) walking, on the streets and roads there are flows of cars (car flows), in public transport passengers are combined into passenger flows. These are flow systems that are modeled by a tetrahedron of states, but have their own identity: their flow units (car or step sizes), their travel distance, their travel time.
 For the qualitative restoration of Ukrainian cities, the identity of transport and pedestrian flows is revealed in comparison with different flow systems. The physical essence of traffic flows, their characteristics and interrelations in time and space are revealed. The simulation was based on the theory of state graphs, which made it possible to establish new characteristics of urban flows, such as traffic intensity, specific intensity, passability, traffic inertia, transience, road and transport potentials, exergy and flow power. The throughput capacity of the highway lane, ways to increase it and reduce congestion are determined.

Multistep continuous flow synthesis of Erlotinib

Erlotinib is an orally administered, highly effective, specific epidermal growth factor receptor tyrosine kinase inhibitor, used to treat non-small cell lung cancer and pancreatic cancer. The traditional synthetic methods for Erlotinib exhibit long reaction time and safety concern. Herein, we describe a novel five-step route for the synthesis of Erlotinib in flow. These five steps comprise etherification, nitration, reduction, addition and cyclization reactions. All steps were optimized and converted to continuous flow process, which drastically reduces the reaction time and considerably improves the process safety as well as the total yield. Enabled by five continuous flow units, Erlotinib is efficiently afforded with an E-factor of 38, an overall yield of 83%, and a total residence time of 25.1 min. Majority steps in this process have been optimized for quantitative conversion, which offers the possibility of telescoping the entire process.