Image Logs Research Articles

Integrated the Core Analysis Data, Image logs, and Conventional Logs to Understand the Reservoir Rock Type of the Mauddud Formation

Integrated the Core Analysis Data, Image logs, and Conventional Logs to Understand the Reservoir Rock Type of the Mauddud Formation

Constraint strategies for estimating in-situ stress from borehole measurements

In this study, we describe strategies to reduce uncertainties in the estimation of in-situ stresses. The strategies are based on the commonly used poro-elastic model with strain corrections for in-situ stress estimation. In addition to the calibration of the minimum horizontal stress magnitudes from measurement data, we further constrain the magnitude of maximum horizontal stress quantitatively with (i) a critical stress state model, (ii) (non)-occurrences of breakout and/or drilling-induced fracture observed from image logs, and (iii) qualitatively with elliptical borehole shapes observed from multi-arm caliper logging data. The methodology is demonstrated using wells near Dawson Creek, Northeast British Columbia and Northwest Alberta, in Western Canada Sedimentary Basin (WCSB). The uncertainty of the estimated maximum horizontal stress magnitude was reduced and the range of the maximum horizontal stress was narrowed after the application of these constraint strategies. It is also observed that in the east of the study area, the in-situ stress regime is a normal fault stress regime. The presence of a normal fault stress regime is unexpected since a strike–slip fault stress regime is typically considered for the entire region. Yet, analysis of caliper data in two horizontal wells has confirmed its presence.

Characteristics, Formation Periods, and Controlling Factors of Tectonic Fractures in Carbonate Geothermal Reservoirs: A Case Study of the Jixianian System in the Xiong'an New Area, China

AbstractAs typical carbonate geothermal reservoirs with low porosity in northern China, the Jixianian System in the Xiong'an New Area is the main target for geothermal fluid exploration. The Jixianian System comprises the Gaoyuzhuang, Yangzhuang, Wumishan, Hongshuizhuang, and Tieling formations. The characteristics, formation periods, and controlling factors of reservoir tectonic fractures have been determined based on analyses of outcrops, cores, thin sections, and image logs. The results show that unfilled fractures account for over 87% and most tectonic fractures are high‐angle shear fractures with angles concentrated at 40° to 70° and the fracture porosity increases linearly with an increased fracture aperture. Within the same tectonic setting and stress field, the lithology and layer thickness are the dominant factors governing the development of tectonic fractures, which are the most developed in dolomites and thin layers. Tectonic fractures were most likely formed in regions near faults or areas with larger stress gradients. The tectonic fractures in the carbonate geothermal reservoirs are roughly divided into four sets: NNW–SSE and NNE–SSW oriented ‘X’‐conjugated shear fractures formed from the Paleozoic to the pre‐Yanshanian Movement; NE–SW‐oriented shear fractures, formed in episode B of the Yanshanian Movement, occurred at the Early Cretaceous; nearly E–W‐oriented tensional fractures formed in the late Yanshanian Movement at the Late Cretaceous to Paleogene, and NEE–SW‐oriented shear fractures formed during the Himalayan movement.

Application of GAN to Resolution Enhancement of LWD Real-Time Image Logs to Support Decision Making

In the current scenario of project management, where the agility and optimization of operations have been prioritized, the practice of logging while drilling (LWD) has gained space compared to traditional wireline logging. In theory, acquiring quality petrophysical properties during drilling brings greater agility in decision making about completion and optimizes operation costs. However, regarding borehole image logs, due to limitations in transmission capacity, the actual available data in real time contain about 50% (for resistivity images) of the full azimuth information, being insufficient for the identification of critical geological structures capable of impacting the communication between production or injection zones or the quality of cementation, such as fractures, caves, and geomechanical collapse zones. The tool’s memory data with the full information may take a few days after the end of drilling to be delivered by the service company, which in some cases is not enough for fast decision making regarding completion. In this work, we tested models based on generative adversarial neural networks (GANs) to reconstruct the complete memory data based on real-time input. As in conventional GAN schemes, a generator is trained to receive a real-time input and create a “memory-like” image, while a discriminator is trained to tell real and fake images apart. To regularize the convergence of training, we used an architecture known in the literature as CycleGAN, where another generator-discriminator pair is trained simultaneously to do the reverse process, recreating the real-time data. Variations of the training process and data sets were used to generate different CycleGAN models. They were trained using logs of presalt reservoirs in Buzios Field, and performance was assessed on logging intervals not seen by the algorithms during training. The results achieved so far have been very promising, as in certain intervals, resultant models were able to capture the presence of fractures and caves. This methodology represents a way of circumventing telemetry limitations, where missing information is added indirectly to the real-time data as the artificial intelligence (AI) algorithm learns the main characteristics of a field/reservoir. Therefore, previous knowledge from the field can be used to continuously optimize future operations, efficiently incorporating the available database into the workflow of petrophysicists for the recognition of geological and geomechanical structures in time to support decision making in completion operations.

WITHDRAWN: The impact of stylolitization on the elastic properties of carbonate reservoirs using laboratory measurements

Stylolitization is one of the most important sedimentary features occurring during diagenetic processes in carbonate rocks. This study experimentally explored how stylolitization and stylolite types affect the elastic behavior of carbonate rocks using hydrostatic tests and ultrasonic measurements. Moreover, petrophysical and well data, including logs (image logs, density, porosity, compressional sonic wave, and shear sonic wave), and Computed Tomography (CT) scans have been used for the selection of appropriate plugs and stylolite classification based on their morphological properties. The observed stylolites were subdivided into four groups: rectangular, seismogram, suture (sharp), and wave-like. To develop new insight into the relationship between stylolites and elastic properties, hydrostatic laboratory tests were conducted under two different saturation conditions: drained (zero pore pressure) and undrained (constant pore pressure). Our results indicate that stylolite-free samples have higher porosity, which suggests that they may have lower velocities. Furthermore, we observed that the stylolitified samples had a higher gradient of VP changes compared with the VS changes, with a strong dependency on the stress state variations (confining and effective pressures). These samples have more potential to contain crack porosities than stylolite-free samples, and stylolites may act as weak surfaces. These weak surfaces can cause different velocity behaviors in the stylolite-bearing samples at low and high pressures (room and reservoir pressures). Our findings indicate that the opening or filling material within the stylolites may have contributed to the increase or decrease in the sonic velocities. If the stylolites are open, then their behaviors are similar to those of crack porosities and can decrease the velocities. However, the filled stylolites showed a positive effect on the velocities depending on the filling materials, which were dense. Finally, this study presents a mechanical anisotropy analysis to identify the origin and type of stylolite.

Comprehensive analysis of stress magnitude and orientations and natural fractures in complex structural regimes oil reservoir: Implications for tectonic and oil field development in the Zagros suture zone

Complex structures with different stress regimes pose challenges in tectonic studies and have implications for the oil and gas industry. The analysis of in-situ stress state and natural fractures in the Dezful Embayment, the southwestern part of the Zagros fold and thrust belt (ZFTB) in Iran, and their implications for tectonic and oil field development are poorly understood. This study analyzes stress orientations, natural fractures, pore pressure (Pp), and stress regime in two oil fields located in the Zagros foothills. The study utilized various data types, including image logs and conventional logs, to determine the in-situ stresses and their implications for energy field development. The results show that the mean orientations of the maximum horizontal stress SH in Field A and Field B are N32°E and N55°E, respectively. The analysis of natural fractures indicates that most tensional fractures are subparallel to the orientation of the maximum horizontal stresses, and the present stress state is responsible for these fractures. The analysis of stress magnitudes demonstrates that the stress regime in Field A changes from thrust faulting toward strike-slip faulting in deeper intervals below water-oil contact. The findings provide valuable insights into the region's reservoir development plans and seismic activities. The orientation of natural fractures suggests that horizontal wells drilled parallel to the orientation of SH can optimize wellbore stability. In addition, the stress variations and complexities observed in Field A are attributed to factors such as folding degree, lateral deformability contrasts, and geological structures like faults. The stress regime analysis indicates the influence of regional tectonic forces and the proximity to the collision boundary. This study will provide valuable insights into the exploration, development, and management of hydrocarbon resources in complex structure regions such as the Dezful Embayment, and it may contribute to understanding stress variations and distribution patterns in similar geological settings elsewhere.

Characteristics and control factors of tectonic fractures of ultra-deep tight sandstone: Case study of the Lower Cretaceous reservoir in Bozi-Dabei area, Kuqa Depression, Tarim Basin, China

The Bozi-Dabei area in the Kuqa Depression host high-quality reservoirs in the Bashijiqike Formation and Baxigai Formation sandstones of the Lower Cretaceous, in which reservoirs yield significant industrial gas flow despite being situated at a considerable burial depth of 8200 m. The geological history of the target formation involves multiple phases of tectonic movements, resulting in the development of multi-genetic fractures that enhance the reservoir's storage and seepage capacity. Based on the results of the drilling core, field profile survey, imaging logging, and experimental analysis, this study presents an analysis of fractures in the Lower Cretaceous dense sandstone reservoir of the Bozi-Dabei area, andclarifies the characteristics and controlling factors of the multi-genesis and multi-period fractures. Additionally, it proposes an effective fracture development model that accounts for geo-stress control. In the Bozi-Dabei area, the prevailing high extrusion stress environment has led to the development of predominantly regional tectonic fractures and fault-related fractures, with relatively gentle deformation-related fractures. The results of a combination of multi-attribute data determination techniques, including fracture filling, inter-cutting relationship, fracture filling isotope, inclusions, and cathode luminescence tests, this study reveals that the reservoir fractures have experienced three major periods of tectonic movement. The regional tectonic fracture development is mainly controlled by stratigraphic lithology and thickness, while the proximity influences fault co-derived fractures to the fault and the relative positions of the upper and lower plates of the fault. The shift in the direction of the late horizontal maximum principal stress leads to the opening or closing of early fractures under different conditions in the Bozi-Dabei area, consequently affecting the degree of fracture opening and effectiveness. Notably, when the horizontal maximum principal stress is deflected to intersect with early fractures at a smaller angle or even superimpose, the fracture effectiveness of the related group system in the deflection direction improves, resulting in an overall coordination. The distribution characteristics of the fracture system in this highly productive reservoir are the result of dominant configurations from multi-phases of geological activities.

New insights into hypogenic non-matrix dissolution mega features driving subsurface fluid movement within the Arab Formation, Saudi Arabia

This paper reports the results of a large integrated study into the classification, distribution and significance of hypogenic non-matrix large-scale dissolution features present in the Arab Formation of Saudi Arabia. The investigation of these features was based primarily on extensive core, wireline caliper, wireline/log while drilling resistivity borehole image logs supported by encountered total lost circulation of drilling fluids and production log data. Dissolution features observed by this study were classified into three main categories: touching vugs, ramiform voids, and cavities. This study is the first to successfully quantify the presence and extent of these non-matrix intervals in this formation, which has greatly improved the 3D modelling efforts. Over 8100 feet of large-scale dissolution features were intersected in both vertical and horizontal wells. The hypogenic genesis of the large-scale dissolution features pre-dates replacement dolomitization in the area. Given the extensive data reviewed, the presented results give insight into the importance of the large-scale dissolution mega features as they are strongly related to total loss of mud circulation during drilling, and will have implications for well-to-well short-cutting during production and impact oil storage capacity.

Natural Fractures and Their Contribution to Natural Gas Migration and Accumulation in Marine Carbonate Reservoirs: Lower Triassic Feixianguan Formation, Northeast Sichuan Basin, China

The Lower Triassic carbonate succession of the Feixianguan Formation represents a primary focus for gas exploration in the northwestern Sichuan Basin. This study area includes the massive Puguang gas field and other nearby gas fields of considerable size. These carbonate reservoirs display significant heterogeneity, which is primarily influenced by the presence of natural fractures. Extensive documentation of fracture types, characteristics, effectiveness, and their role in enhancing reservoir properties was conducted by examining and analyzing various data sources, including cores, thin sections, image logs, and experimental measurements. Shear fractures primarily characterize the Feixianguan Formation carbonate reservoir, although tensile and diagenetic fractures are also present, albeit in fewer numbers. Tectonic fractures are the dominant type, particularly unfilled ones with dip angles greater than 60° in the NEE–SWW direction. These fractures are mainly filled with calcite. The tectonic fractures were formed in three stages: Late Indosinian-Early Yanshanian, Late Yanshanian-Early Himalayan, and Late Himalayan. These fractures intersect with the in situ stress direction at a small angle in the NE–SW, NEE–SWW, and near E–W directions, contributing to their effectiveness. Compared with the total fracture density, the effective fracture density is the factor in controlling gas production. An increase in the proportion of effective fractures tends to result in a rise in gas productivity. Additionally, the orientation of effective fractures also influences natural gas production. Fractures striking in the E–W and NE–SW directions, which are particularly effective, are associated with high natural gas production.

A novel evaluation method of dolomite reservoir using electrical image logs: The Cambrian dolomites in Tarim Basin, China

The Cambrian dolomites in Tarim basin are important hydrocarbon exploration targets. However, these ancient dolostone reservoirs are deeply buried, and the lithology and reservoir space are complex, therefore the logging evaluation of reservoir effectiveness is difficult. This study analyzes the log response characteristics using core data and electric image logs, and divides the dolomite reservoir into four types: pore type, fracture type, vug type and fracture-vug type. Among them, the vug type and fracture-vug type are the main reservoir types with the highest industrial production. Then, this study innovatively proposes the method of point-by-point calibration of electrical image log, which avoids the difference in response characteristics of various electrical image log instruments, and reduces the uncertainty caused by human factors of conventional calibration. The point-by-point calibration method uses local data for comparison and calculates calibration coefficient automatically. The calibrated electrical image log data can maintain better matching and consistency with conventional resistivity in high and low resistivity simultaneously, and it is more truly reflect the borehole-wall resistivity, consequently, can establish a foundation for subsequent reservoir evaluation. Finally, according to the calibrated electrical image log data and the 360° roll-scan core photos, the vugs in-plane porosity on electrical image, the vug connectivity and the porosity spectrum are used to identify reservoir types and evaluate reservoir effectiveness. The vugs in-plane porosity on electrical image can truly reflect the development of fractures and vugs, and quantitatively evaluate the vugs and fractures of the whole borehole-wall by calibrating with core. The vug connectivity index can indicate the isolated vugs and connected vugs, and quantitatively evaluate the connectivity of vugs and fractures, in addition the porosity spectrum can reflect the pore structure of reservoir and identify the reservoir with secondary porosity. The coupling of the three methods can accurately identify high-quality dolomite reservoirs with vugs and good connectivity. This novel technology adopts the idea of classification and identification before quantitative evaluation and establishes a new bridge from qualitative analysis to quantitative evaluation. The method proposed helps improve the interpretation accuracy and coincidence rate and provides a reference for the comprehensive evaluation of ultra-deep dolomite reservoirs in the Tarim basin and worldwide.

Three‐dimensional stratigraphic architecture, secondary pore system development and the Middle Pleistocene transition, Sandy Point area, San Salvador Island, Bahamas

AbstractThe Bahamian Archipelago has been the subject of extensive studies of stratigraphy, carbonate island morphology and diagenetic overprinting for many decades. A recently‐acquired dataset comprised of high‐resolution light detection and ranging, tightly spaced cored boreholes with image logs, thin sections, porosity and permeability measurements, and isotopic geochemical analyses provides a unique opportunity to perform detailed sequence stratigraphic analysis. This multi‐faceted study first establishes a new high‐resolution sequence stratigraphic framework for the Sandy Point area of San Salvador Island, encompassing six unconformity bound sequences (exposure surfaces) representing varying lengths of missing time. The stratigraphically lowest sequence is Late Pliocene in age and is dominated by reef facies capped by an extensive laminar caliche that represents 1.5 million years of exposure. The overlying Early Pleistocene is split into two sequences, EP1 and EP2, which are both dominated by low‐energy subtidal facies. The upper three sequences are tied to the Marine Isotope Stage 11, 9 and 5e interglacials, and are distinctly different in facies composition and architecture, being dominated by higher energy facies distributed in a more complex mosaic. The new stratigraphic framework highlights significant changes in depositional style and facies architecture that can be linked to increasing sea‐level amplitude oscillations and greater climate gradient at the Mid Pleistocene Transition. The well‐constrained framework is then used to provide key context for observed complex diagenetic evolution through repeated sea‐level inundation and subaerial exposure. These results suggest that well‐developed subaerial exposure surfaces drive increases in non‐matrix features in the subsequent stratigraphic package following exposure as the well‐cemented exposure surface acts to concentrate fluid flow and dissolution. Integration of non‐matrix features within this framework highlights the importance of dissolution/cementation patterns on formation of these modified unconformity surfaces for focusing later meteoric diagenesis and creating enhanced fluid flow pathways for continued multicyclic diagenetic events.

A New Approach of Well Productivity Evaluation for Fractured Buried Hill Gas Reservoirs Based on Imaging Logging Data

Fractures function as storage spaces and effective seepage channels for metamorphic rock buried hill reservoirs. Their effectiveness and permeability govern the content and enrichment of oil and gas. Owing to the convoluted distribution patterns of fractures, it is arduous to gauge the effectiveness and permeability of fractures with precision, thus rendering well productivity prediction difficult. This article cites fractured gas reservoirs in a metamorphic rock buried hill as an example. Through comprehensive usage of core and imaging logging data to finely interpret fractures, calculate the fracture parameters that control productivity, including fracture density, fracture width, and fracture porosity. According to the evaluation index of fracture effectiveness, the method of constructing effectiveness index is proposed to quantitatively evaluate the effectiveness. Combined with the study of the law of influence of fracture parameters on reservoir permeability, the permeability index is established to reflect permeability. Productivity coefficients for fractured reservoirs with pollution factors have been established by using well-test interpretation data. To evaluate the well productivity of buried hill reservoirs, a productivity assessment chart is constructed by integrating the fracture effectiveness index, permeability index, and productivity coefficient. This chart enables prompt predictions of the buried hill reservoir’s productivity. In order to verify the reliability of the method, a comprehensive comparison is made through conventional, array acoustic logging data and test data. The results show that the method is well applied in the evaluation of metamorphic rock buried hill reservoirs and provides a new idea for the rapid prediction of well productivity.

Identification of natural fractures in shale gas reservoirs using fracture signature function and machine learning models

Identifying fractures is important for optimizing recovery and enhancing oil recovery techniques. Identifying natural fractures using FMI and cores is expensive and unavailable for all wells. Therefore, predictive models based on conventional wireline logs are necessary. Extreme Gradient Boosting, Decision tree, Random Forest, Support Vector Machine, Feed Forward Neural Network, and Recurrent Neural Network were applied to identify natural fractures. This study uses well logs to develop a new Fracture Signature Function equation for determining natural fractures in the shale reservoir. This unsupervised approach requires no special image log to identify natural fractures. However, the class imbalance problem between the fracture and non-fractured zone often restricts the accuracy of the machine learning models, which require a predictive model not dependent upon the special logs and class imbalance problems in the prediction of fractured zones. Synthetic Minority Oversampling (SMOTE) and Random Oversampling (ROS) were applied to solve the class imbalance problem in the data. The results show that the machine learning models did not predict the fracture and non-fracture zones with acceptable accuracy even after applying SMOTE and ROS. Relative to all machine learning models, Random Forest predicted the results with the highest accuracy of 91 % and F1-Score of 17.6 %. The Fracture Signature Function (FSFn'') predicted the natural fractures with high accuracy except in zones with very complex borehole environments. A Forward Neural Network is more efficient in identifying fracture and non-fractured zones in imbalance class problems of the dataset. The Recurrent Neural Network's predictions were biased toward the major class related to the non-fractured zone of the studied interval. The newly developed equation can be used for natural fracture identification in drilling and production strategy design by using the easily available well-log data in class imbalanced conditions.

Curvature analysis and its correlation with faults and fractures in presalt carbonates, Santos Basin, Brazil

Presalt lacustrine carbonate reservoirs in the Santos Basin, Brazil, can have a high degree of fracturing. Properly characterizing such properties is important due to their influence on the porosity–permeability system. It may play a key role in the so-called excess permeability features and the flow behaviour, especially in the Aptian Alagoas Stage. Therefore, 3D characterization of the fracture system improves the reservoir model. For this purpose, correctly identifying the fault and fracture zones in seismic data is crucial. This task is generally performed manually and guided by amplitude interpretation or geometric seismic attributes. However, due to the seismic resolution of the pre-salt seismic datasets, many faults and fractured zones are not identified in the seismic amplitude domain or by standard geometric attributes such as coherence. Improving the resolution of seismic data and its geometric attributes can positively impact the delineation of fractured zones, structural lineaments, and their connectivity. Curvature (k) attributes have a high potential to reveal vertical to subvertical subseismic-scale structures, which is the main type of strain generated from the tectonic style in the Pre-salt rocks. Among the curvature attributes, the most-positive (k1) and the most-negative (k2) attributes are some of the most commonly used. The present study evaluates the use of seismic inverse Q-filter and three different dip estimation techniques based on Fast Fourier Transform (FFT), Principal Component Analysis (PCA), and Phase Gradient (PG). It also adds two postfiltering techniques (median and recursive Gaussian filters) to obtain a consistent most-positive curvature. We then analyse two analytical models that correlate the volumetric fracture intensity, measured on Borehole Image Logs (BHI), with the curvature. Then, we perform a comprehensive study to understand the role of seismic-scale strain (translated into curvature) and mechanical stratigraphy in the development of fractures in the presalt, where we address that in addition to seismic-scale deformation, the contents of silica, clay, and organic matter are also relevant variables. These results can help to guide future studies of fracture characterization to prospect naturally fractured reservoirs or to estimate fracture intensity for dual-porosity reservoir modelling on the Santos presalt carbonates.

Rock Typing and Reservoir Quality Analysis of the Abu Madi Reservoir: Distribution Prediction Using Artificial Neural Networks in the West El Manzala Area, Onshore Nile Delta, Egypt

In the Nile Delta gas province of Egypt, the Abu Madi Formation is the most promising sandstone gas reservoir. This study aimed to investigate reservoir rock typing and quality by integrating petrophysical and petrographical data, including well logs, image logs, and cores. Furthermore, it sought to predict the permeability and reservoir quality of uncored wells by integrating artificial neural network technique with core analysis data and evaluate the effectiveness of this approach as an exploration tool in the West El Manzala area. The core petrography revealed the presence of microfacies consisting of arenites and wackes. The measured porosity, permeability, and pore sizes obtained from the cores, along with the parameters of the reservoir quality index, normalized porosity, and flow zone indicator, indicated that the Abu Madi reservoirs could be subdivided into three categories based on reservoir quality. High reservoir quality (RT-I) is characterized by megapores within the hydraulic flow unit (HFU-1) associated with bioturbated coarse to gravelly sandstone facies. Moderate reservoir quality (RT-II) is characterized by macropores within the hydraulic flow unit (HFU)-II associated with massive coarse to gravelly sandstone facies. Poor reservoir quality (RT-III) was characterized by mesopores within the HFU-III hydraulic flow unit related to laminated silty mudstone facies. The findings of this study demonstrate that the combination of reservoir rock typing and artificial neural networks is an extremely successful method for petroleum exploration in the West El Manzala region.

Fracture Conductivity Work Flow Models Well Spacing, Completions Design

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2023-3864710, “A Comprehensive Simulation Study of Hydraulic Fracturing Test Site 2 (HFTS-2): Part I—Modeling Pressure-Dependent and Time-Dependent Fracture Conductivity in Fully Calibrated Fracture and Reservoir Models,” by Han Li, Jichao Han, SPE, and Jiasen Tan, SPE, Occidental Petroleum, et al. The paper has not been peer reviewed. _ Combining fracture and reservoir diagnostic analysis with integrated geomechanics and reservoir simulation is an efficient and cost-effective approach to generate realistic fracture geometry, understand fluid flow behavior, and define fracture-conductivity distribution in unconventional reservoirs. The complete paper presents a case study of integrated geomechanical and reservoir simulation with a developed fracture-conductivity-calculation work flow that was validated with diagnostic results to evaluate well spacing and completions design. Introduction This study extends that of previous authors by matching field fracture diagnostics and reservoir simulation using variable fracture conductivity. In the example used by the authors from the Hydraulic Fracturing Test Site 2 (HFTS-2) development, multiple fracture diagnostic methods were used to calibrate hydraulic fracture models. Once the model was calibrated, a new proppant-conductivity algorithm assigned conductivity values along the hydraulic fractures based on a physics-based model calculation of proppant concentration. Multiple mechanisms, such as stress- and pressure-dependent effects, time-dependent conductivity degradation, unpropped fractures, and proppant embedment, can all be considered in the novel fracture-conductivity-calculation methodology. Fracture-Conductivity-Calculation Work Flow The conductivity work flow developed by the authors uses simulated proppant concentration from a fracture model and experimental conductivity measurements of propped and unpropped fractures to define variable conductivity along hydraulic fractures. Conductivity measurements included sets of long-term (50-hour) experimental fracture-conductivity tests with various mesh sizes, proppant types, and closure stresses. The conductivity-calculation work flow developed by the authors was applied to the integrated simulation project of multifractured horizontal wells in the HFTS-2 project. Fig. 1 shows a flow chart of the work flow from fracture propagation modeling through integrated reservoir simulations. In general, the work flow consists of developing a 3D geological model, creating and calibrating parent wells’ hydraulic fracture models, calculating the fracture conductivity based on proppant concentration, history-matching the parent wells’ production and constraints with reservoir simulation, performing fracture-propagation modeling for child wells, and history matching and predicting the estimated ultimate recovery (EUR) for the entire pad. HFTS-2 Project Overview The HFTS-2 is in the Delaware Basin and is a cost-shared, field-based project designed to study hydraulic fracturing processes and production using state-of-the-art diagnostics, including fiber optic (FO) distributed temperature sensing and distributed acoustic sensing (DAS) pressure monitoring, image logs, cores through the fractures, and microseismic monitoring. Many studies have detailed the project overview of the HFTS-2, and this paper’s authors only include the overview of completions in the HFTS-2 project.

In situ stress field detection of stress-induced strong anisotropy media based on Mohr circle theory

The prediction and evaluation of in situ stress field plays an important role in many engineering fields. How to accurately obtain in situ stress field information of a large area becomes a focus in geophysics. Wide-azimuth seismic data establish a bridge between in situ stress and rock anisotropy, making it possible to predict the large-scale in situ stress field. Ellipse fitting (EF) is a common method to predict in situ stress according to the characteristics of seismic attribute change with azimuth, but there are some problems such as 90° ambiguity in orientation prediction and the unclear stress-related physical meaning of the fitting parameters. Moreover, the variation of azimuthal seismic attribute in strongly anisotropic media does not meet ellipse hypothesis, which also limits the application of EF method. Through mathematical simulation experiment, the mechanism of seismic response characteristics under orthotropic stress situation is explored. Focusing on the property of strong anisotropy induced by in situ stress in subsurface media, a new stress circle fitting (SCF) method for in situ stress prediction is established by combining the azimuthal variation characteristics of reflection coefficient with the Mohr circle theory. The fitting results have clear physical significance related to in situ stress. In addition, through analysis of fitting parameters, the influence of 90° ambiguity problem can be eliminated. EF and SCF methods are applied to actual wide-azimuth seismic data. Comparison indicates that the SCF result is more suitable for azimuth seismic data in strongly anisotropic media. Compared to EF, in situ stress field distribution predicted by SCF method is more reasonable. The actual imaging logging results also prove the accuracy of SCF method.

Identification of Shale Lithofacies from FMI Images and ECS Logs Using Machine Learning with GLCM Features

The identification of sedimentary structures in lithofacies is of great significance to the exploration and development of Paleogene shale in the Boxing Sag. However, due to the scale mismatch between the thickness of laminae and the vertical resolution of conventional wireline logs, the conventional lithofacies division method fails to realize the accurate classification of sedimentary structures and cannot meet the needs of reservoir research. Therefore, it is necessary to establish a lithofacies identification method with higher precision from advanced logs. In this paper, a method integrating the gray level co-occurrence matrix (GLCM) and random forest (RF) algorithms is proposed to classify shale lithofacies with different sedimentary structures based on formation micro-imager (FMI) imaging logging and elemental capture spectroscopy (ECS) logging. According to the characteristics of shale laminae on FMI images, GLCM, an image texture extraction tool, is utilized to obtain texture features reflecting sedimentary structures from FMI images. It is proven that GLCM can depict shale sedimentary structures efficiently and accurately, and four texture features (contrast, entropy, energy, and homogeneity) are sensitive to shale sedimentary structures. To accommodate the correlation between the four texture features, the random forest algorithm, which has been proven not to be affected by correlated input features, is selected for supervised lithofacies classification. To enhance the model’s ability to differentiate between argillaceous limestone and calcareous mudstone, the carbonate content and clay content calculated from the ECS logs are involved in the input features. Moreover, grid search cross-validation (CV) is implemented to optimize the hyperparameters of the model. The optimized model achieves favorable performance on training data, validation data, and test data, with average accuracies of 0.84, 0.79, and 0.76, respectively. This study also discusses the application of the classification model in lithofacies and production prediction.

Markerless dynamic tumor tracking (MDTT) radiotherapy using diaphragm as a surrogate for liver targets.

To assess the feasibility of using the diaphragm as a surrogate for liver targets during MDTT. Diaphragm as surrogate for markers: a dome-shaped phantom with implanted markers was fabricated and underwent dual-orthogonal fluoroscopy sequences on the Vero4DRT linac. Ten patients participated in an IRB-approved, feasibility study to assess the MDTT workflow. All images were analyzed using an in-house program to back-project the diaphragm/markers position to the isocenter plane. ExacTrac imager log files were analyzed. Diaphragm as tracking structure for MDTT: The phantom "diaphragm" was contoured as a markerless tracking structure (MTS) and exported to Vero4DRT/ExacTrac. A single field plan was delivered to the phantom film plane under static and MDTT conditions. In the patient study, the diaphragm tracking structure was contoured on CT breath-hold-exhale datasets. The MDTT workflow was applied until just prior to MV beam-on. Diaphragm as surrogate for markers: phantom data confirmed the in-house 3D back-projection program was functioning as intended. In patients, the diaphragm/marker relative positions had a mean±RMS difference of 0.70±0.89, 1.08±1.26, and 0.96±1.06mm in ML, SI, and AP directions. Diaphragm as tracking structure for MDTT: Building a respiratory-correlation model using the diaphragm as surrogate for the implanted markers was successful in phantom/patients. During the tracking verification imaging step, the phantom mean±SD difference between the image-detected and predicted "diaphragm" position was 0.52±0.18mm. The 2D film gamma (2%/2mm) comparison (static to MDTT deliveries) was 98.2%. In patients, the mean difference between the image-detected and predicted diaphragm position was 2.02±0.92mm. The planning target margin contribution from MDTT diaphragm tracking is 2.2, 5.0, and 4.7mm in the ML, SI, and AP directions. In phantom/patients, the diaphragm motion correlated well with markers' motion and could be used as a surrogate. MDTT workflows using the diaphragm as the MTS is feasible using the Vero4DRT linac and could replace the need for implanted markers for liver radiotherapy.

Fractured Zone Detection Using Petrophysical Logs by Rescaled Windowed R/S Analyses and Discrete Fracture Network (DFN) of Yanchang Formation in Mahuangshan-Hongliugou Area, Ordos Basin, China

Structural fractures generally develop in the upper crust strata and are usually distributed in a convergent pattern, forming structural fracture zones with a specific strike. Fracture zones control the reservoir seepage system and seriously affect the migration and accumulation of oil and gas in tight sandstone reservoirs. Therefore, characterizing the characteristics of the fracture zones for tight oil exploration and development effectively is essential. In this paper, the variable scale fractal method is introduced to calculate the petrophysical log, and a new curve H is built. An intensity log is to characterize the intensity of structural fracture development. The H curve is in a good linear relationship with the intensity curve after the comparison of the H curve and intensity curve in 32 wells. A quantitative relationship between H and the intensity curve is established. Based on the parameters obtained from the core and image logs, the discrete fracture network model was established using H curves from more than 300 wells, and the structural fracture zone was analyzed. The model shows that the fracture zones formed by structural fractures are in S-N and NW-SE directions in the study area. The orientation of the structural fracture zone is consistent with that of the fractured fault zone and fault, and the development of the fractured zone is consistent with the regional tectonic evolution characteristics. The characteristics of the fracture zone explain the distribution law of oil accumulation and groundwater salinity in the study area.