Image Logs Research Articles

Multi-component induction logging detection characteristics of the fracture azimuth and dip angles and the fast extraction methods of fracture distribution parameters

In the field of log interpretation of tight sandstone and shale reservoirs, it is difficult to quantitatively evaluate the fracture distribution parameters (fracture azimuth angle and fracture dip angle) near the borehole. Multi-component induction logging can measure the apparent resistivities of the reservoir in different directions by an orthogonal coil system, which lays a foundation for the quantitative evaluation of the fracture distribution parameters near the borehole. First, we derive the finite element equations for numerical calculation from the Maxwell equations for the time-harmonic field and construct a three-dimensional (3D) vector finite element numerical algorithm for the fractured formation. Second, we quantitatively analyze the multi-component induction logging detection characteristics of the fracture azimuth and dip angles. Third, we establish a fast extraction method of the fracture azimuth angle based on coordinate system rotation and an analytical calculation method of the fracture dip angle using the combination of cross components and coplanar components of multi-component induction logging. Finally, we use field data to test the fracture distribution parameter extraction method, and the fracture dip and azimuth angles calculated by multi-component induction logging are consistent with those calculated by borehole imaging logging, which realizes the fast extraction of the distribution parameters of fractures in tight sandstone and shale reservoirs.

Prediction of lithology in lacustrine carbonates using well logs: The Cretaceous Barra Velha Formation in Santos Basin, offshore Brazil

Abundant hydrocarbons have been produced from the pre‐salt lacustrine carbonates of the Cretaceous Barra Velha Formation in the Santos Basin of offshore Brazil. The highly heterogeneous lithology and pore systems make it difficult to predict the reservoir quality via petrophysical well logs. Core description, computed tomography (CT) scanning, thin sections and wireline well logs are utilized to characterize the lithology, pore spaces are reservoir quality of the Cretaceous Barra Velha Formation pre‐salt lacustrine carbonates in the Santos Basin. The results show that the lithology mainly includes shrubstone, grainstone, laminated micrite and massive micrite. The pore systems are dominated by secondary pores, such as intergranular pores, dissolution pores and intercrystalline pores as well as modified primary pores. Geological well logs (conventional well logs, electrical and sonic image logs and nuclear magnetic resonance [NMR] logs) are integrated to build the predictable models of the carbonate reservoirs. The shrubstone, which is dominated by intergranular pores, has the highest reservoir quality, which can be derived from NMR logs. Grainstone contains both primary intergranular pores and abundant secondary dissolution pores. The laminated and massive micrite contain only micropores and therefore have the lowest reservoir quality. Lastly, conventional well logs integrated with electrical and sonic image logs are utilized to predict the distribution of lithology and reservoir quality in single wells, and the results are testified by the NMR log data. The shrubstone and grainstone are future exploration targets of the Cretaceous Barra Velha Formation in the Santos Basin. The results are hoped to give insights into the petrophysical behaviours of various lithologies, and provide theoretical and technical guidance for reservoir evaluation and prediction.

Fracture characterization of Asmari Formation carbonate reservoirs in G Oilfield, Zagros Basin, Middle East

The Asmari Formation in the G oilfield on the Iran-Iraq border is a fractured-porous multi-lithology mixed reservoir, for which fracture is an important factor affecting oil productivity and water cut. The characterization and modeling of fractures in the carbonate reservoir of G oilfield are challenging due to weak conventional well log responses of fractures and a lack of specific logs, such as image logs. This study proposes an integrated approach for characterizing and modeling fractures in the carbonate reservoir. The features, formation mechanism, influencing factors, and prediction methods of fractures in the Asmari Formation carbonate reservoirs of G oilfield were studied using core observation, thin section, image log, cross-dipole acoustic log (CDAL), geomechanics numerical simulation (GNS), and production data. According to CDAL-based fracture density interpretation, GNS-based fracture intensity prediction between wells, and DFN-based rock fracture properties modeling, the quantitative fracture characterization for G oilfield was realized. This research shows that the fractures in the Asamri Formation are mainly medium-to high-angle shear fractures. The substantial compression stress during the Miocene played a major role in the formation of the prominent fractures and determined their trend in the region, with primary trends of NNW-SSE and NNE-SSW. The fracture distribution has regularity, and the fractures in zone A dolomites are more highly developed than that in zone B limestones vertically. Horizontally, fractures intensity is mainly controlled by faults and structural location. The results of this study may benefit the optimization of well design during field development. From 2019 to 2021, three horizontal wells pilot tests were deployed in the fractures belt in zone A, and these fractures prominently increased the permeability of tight dolomite reservoirs. The initial production of the wells is four to five times the average production of other wells in the area, showing a good development effect. Meanwhile, the updated numerical simulation validates that the history match accuracy of water cut based on the dual-porosity model is significantly improved, proving the fracture evaluation and prediction results to be relatively reliable and applicable.

Formation Timing and Features of Stylolites and Controlling Factors for the Second-Period Stylolites in the Carboniferous KT-I Formation of NT Oilfield

The formation timing of stylolites, which is of great importance for analyzing the controls of stylolites, has nearly never been examined. In this paper, based on the data of cores, imaging logging, conventional logging, and mercury injection, the characteristics of stylolites formed in different stages of tectonic movement were investigated, and the controlling factors of oil-stained stylolites, formed in the second period of tectonic movement, were analyzed in particular. Furthermore, the influence of different controlling factors on the development of stylolites was compared, by using grey correlation analysis. The results show that there are three periods of stylolites in the study area, and all three periods developed both low-angle stylolites and high-angle stylolites. The prominent characteristics of both the low-angle and high-angle stylolites of the second period, are being oil-stained. The higher the structural location, the greater the buried depth, the lower the dolomite content, the higher the calcite content, the higher the clay content, the smaller the rock density, the greater the porosity, the smaller the rock grain size, the easier it is to develop both the low-angle stylolites and the high-angle stylolites. The influence of different controlling factors on the development of low-angle stylolites is given by depth, porosity, curvature, rock density, rock grain size, clay content, dolomite content, and calcite content, in this order. The importance of the influences on the development of high-angle stylolites proceeds as follows: curvature, calcite content, depth, rock particle size, clay content, rock density, dolomite content, and porosity. Tectonism is the most important influencing factor on the development of stylolites.

Excess Anisotropy: A Method to Predict Frequency of Resistive Fractures in the Wolfcamp Shale

A horizontal well in the Wolfcamp Formation within the Delaware Basin exhibits cross-dipole sonic log anisotropy varying from 0.0% to 29.7% over the reservoir interval. Massive limestones exhibit little anisotropy while shales and intervals with high fracture counts have high anisotropy. Integrated analysis of acoustic, image and triple combo open-hole log data indicates that the computed volume of shale log is a strong predictor of anisotropy with a simple linear relationship. However, there is much anisotropy that is not accounted for by this lithologically related linear relationship. We refer to the residual obtained by subtracting the predicted anisotropy using this relationship from the measured anisotropy from a cross-dipole sonic tool as the excess anisotropy. The excess anisotropy is the remaining anisotropy that is not accounted for by linear regression between the volume of shale log and the measured anisotropy. We find that the excess anisotropy is linearly correlated to the resistive fracture density. Linear regression between the two variables yields a statistically significant relationship that enables a rough estimation of the resistive fracture frequency from the excess anisotropy. Validation in a second well produces a similar correlation to fracture frequency.

Initiative global NILS control in source and mask optimization for process window enhancement.

Semiconductor processing is becoming more challenging as integrated circuit dimensions shrink. An increasing number of technologies are being developed for the purpose of ensuring pattern fidelity, and source and mask optimization (SMO) method has outstanding performances. In recent times, owing to the development of the process, more attention has been paid to the process window (PW). As a crucial parameter in lithography, the normalized image log slope (NILS) is strongly correlated with the PW. However, previous methods ignored the NILS in the inverse lithography model of the SMO. They regarded the NILS as the measurement index for forward lithography. This implies that the optimization of the NILS is the result of passive rather than active control, and the final optimization effect is unpredictable. In this study, the NILS is introduced in inverse lithography. The initial NILS is controlled by adding a penalty function to ensure that it continuously increases, thus increasing the exposure latitude and enhancing the PW. For the simulation, two masks typical of a 45-nm-node are selected. The results indicate that this method can effectively enhance the PW. With guaranteed pattern fidelity, the NILS of the two mask layouts increase by 16% and 9%, and the exposure latitudes increase by 21.5% and 21.7%.

Heterotic Classification of Inbred Lines of Maize Based on Combining Ability for Kernel Yield

Grouping of maize inbred lines into heterotic groups is an initial step in exploitation of heterosis. Hence a field study was conducted to classify 27 inbred lines into two heterotic groups by evaluating the performance of 54 crosses along with lines and testers in a simple lattice design. The 27 inbred lines were crossed to two broad based heterotic testers. Highly significant differences were noticed for kernel yield per plant, days to anthesis, days to silking and plant height among all the genotypes. One cross PI 330 × LM 13 was found to be promising among the crosses. Highly significant GCA and SCA effects for kernel yield per plant was recorded. Five inbred lines were identified as good general combiners for kernel yield per plant while nine test crosses were found to be good specific combiners. Out of 27 inbred lines, the testers could classify 15 inbred lines into heterotic groups based on GCA and SCA effects and mean kernel yield per plant. The study demonstrated the applicability of combining ability effects in classifying the inbred lines.

Typical misinterpretations and scientific concepts in well-logging geologic studies

The method and theoretical system of well logging geology have been widely used in the fields of basic geology, petroleum geology and engineering geology, but the different response sensitivity of different well logging series to geological information and the mismatching between geophysical properties of multiple well logs and geological genesis of rocks frequently result in misunderstandings in the research process of well logging geology. Therefore, it is in an urgent need to analyze the typical misunderstanding cases in the research of well logging geology and explore the corresponding scientific ideas and countermeasures. After analyzing the typical misunderstandings in the research of well logging geology, this paper investigates vertical resolution scale of various logging series and its contradiction with detection depth and illustrates the importance of the integration of different scales of data. In addition, the factor inducing “fake logging data” and its influence on interpretation evaluation are clarified and a set of ideas for well logging evaluation of geological interpretation is put forward. And the following research results are obtained. First, the typical misunderstandings in the research of well logging geology can be classified into two categories, namely geological body interpretation misunderstanding and reservoir property parameter calculation misunderstanding. Second, special geological phenomena, such as high-density and high-resistivity mudstone can lead to logging data ambiguity, so attention shall be paid to petrophysical response mechanisms during geological logging interpretation. Third, to carry out well logging evaluation of unconventional oil and gas, it is necessary to integrate new technologies of electric imaging logging, dipole acoustic logging and nuclear magnetic resonance logging, and the calibration of core data and the integration of geological ideas can improve the interpretation accuracy. Fourth, In the process of borehole structural logging analysis, sedimentary response, geostress evaluation and fracture identification, geological ideas shall be integrated to avoid the logging interpretation misunderstanding caused by the same response of different geological phenomena in well logs. In conclusion, the dialectical and systematic thinking from geology to logging and then to geology, from practice to recognition and then to practice and from “a narrow view” to “a broad view” can provide a scientific ideas for the comprehensive research of well logging geology.

Formation of multi-stage and clustered fractures at 3.6–4.9 km in the Shizigou structure, SW Qaidam basin

In the Eocene Upper Xiaganchaigou Formation from depths of about 3.6–4.9 km in the Shizigou (SZG) Structure in the SW Qaidam basin, core and image logs reveal three fracture assemblages (A-C) comprising opening-mode fractures and faults. Assemblages are defined by structural style (groups of fracture types), and orientation patterns and thus kinematics and separated by relative timing by the unlithified rock style of deformation of assemblage A and fracture crosscutting relations between assemblages B and C. Correlation of fracture kinematics with the structural history of the basin suggests a multi-stage fracture population in the Shizigou Structure arising as a response to Eocene transtension, Miocene transpression, and Quaternary shortening under the influence of the Cenozoic evolution of two boundary faults, the Altyn Tagh Fault (ATF) and the Qimen Tagh-Eastern Kunlun Fault (QTEKF). To clarify the relation, we document formation process of multi-stage fractures in cores and their preferred orientations in log images in five wells. Using image logs from horizontal wells (Shi A and B) at ca. 3.7–3.9 km depth and statistical methods for quantifying spatial arrangement patterns, we identified statistically significant conductive fracture clusters; opening-mode fractures of the assemblage B are significantly hierarchically clustered. Combining fracture mode and their preferred orientations with reconstructed stress history, we propose that the deformation history of the fracture population is kinematically related to the Cenozoic activity of the ATF and the QTEKF. The initial stage of fracture formation is associated with Eocene strike-slip faulting along the ATF, followed by the Early Miocene initial transpressional faulting along the QTEKF and finally intensified shortening since the Quaternary, respectively.

Hypogenic origin of paleocaves in the Ordovician carbonates of the southern Tahe oilfield, Tarim basin, northwest China

The Lower-Middle Ordovician paleocaves at the depths of over 6000 m in the southern Tahe Oilfield have been important objectives of petroleum production in the Tarim Basin. 3D seismic data, drilling well data, image logs, and cores were integrated to delineate the development characteristics, spatial distribution, and morphology of paleocave reservoirs in the Tahe Oilfield. The petrographic, geochemical features and fluid inclusion measurements of the cave and fracture-filling calcite in the Tahe Oilfield were subsequently performed. The formation mechanism of paleocaves in the southern Tahe Oilfield was revealed through the comparative analysis of paleocaves in the north and south of the Tahe Oilfield. The paleocaves in the northern and southern Tahe Oilfield are extensively distributed 0–150 m and 160–350 m away from the regional unconformity, respectively. Different from the diverse paleocave morphologies including single cave passages, anastomotic mazes, and branchwork passages in the northern Tahe Oilfield, the paleocaves in the southern Tahe Oilfield are dominated by isolated chambers and rising shafts. Additionally, almost all the cave and fracture-filling calcite cements in the northern Tahe Oilfield coexist with gray-green sand and clay. While, the cave-filling calcite cements are relatively clean, without any terrigenous minerals. Furthermore, the calcite samples in the northern Tahe Oilfield show δ13C and δ18O values varying from −5.90‰ to −0.39‰, and from −13.47‰ to −7.23‰, respectively. The calcite cements in the southern Tahe Oilfield present similar δ13C values with the Ordovician limestone samples and relatively more negative δ18O values in a range between −15.02‰ and −12.29‰. Compared with the calcite samples in the norther Tahe Oilfield, the cave-filling calcite in the southern Tahe Oilfield shows a narrower range of 87Sr/86Sr ratios varying from 0.709342 to 0.709689. In particular, large amount of two-phase aqueous inclusions observed in the calcite from the southern Tahe Oilfield display relatively higher homogenization temperatures ranging from 90.8 °C to 205.9 °C. These significant differences on the paleocaves between the north and south of the Tahe Oilfield suggest that the paleocaves in the south are overprinted by both gravity-driven deep circulating meteoric water during the early Hercynian and the ascending thermal water possibly occurring from the second episode of the middle Caledonian to the early Hercynian. The paleocaves in the southern Tahe Oilfield are interpreted to be generated by hypogene karst under the constraints of strike-slip fault system and lithostratigraphic sequence in the Ordovician in confined settings. This study is an important supplement to the previous Ordovician meteoric karst model in unconfined zones of the Tahe Oilfield. It indicates that the stratabound isolated paleocaves developed in the lower submember of the Upper Yingshan Formation in the southern Tahe Oilfield have significant exploration potentials.

A Numerical Model for Pressure Analysis of a Well in Unconventional Fractured Reservoirs

Fractured reservoirs are highly heterogeneous in both matrix and fracture properties, which results in significant variations in well production. Assessing and quantifying the influence of fractures on fluid flow is essential for developing unconventional reservoirs. The complicated effects of fractures in unconventional fractured reservoirs on fluid flow highly depend on fracture geometry, fracture distribution, and fracture properties, which can be reflected in pressure transient testing. The biggest challenge lies in delineating the pre-existing natural fracture distribution pattern, density, azimuth, and connectivity. Using the advanced finite element method, this paper builds a finely characterized near-wellbore model to numerically simulate the pressure transient testing process in naturally fractured reservoirs and further evaluates fracture-related effects to obtain a more accurate solution. First, the numerical program is benchmarked by the analytical solutions and numerical results of Eclipse. Next, different fracture models with single fractures or fracture networks are set up to investigate the effects of fracture parameters numerically (e.g., fracture location, fracture dip angle, fracture spacing, the ratio of fracture permeability to matrix permeability, fracture network orientation, horizontal fracture distribution, etc.) on pressure transient behaviors in naturally fractured reservoirs. Velocity and pressure profiles are presented to visualize and analyze their effects, and new features in the flow regimes of the derivative plots of the bottom-hole pressure are identified and discussed. Finally, based on geological and geophysical data, including image logs, core descriptions, wireline logs, and seismic and well test data, a practical fractured model of the Dalwogan 2 well in the Surat basin is built, analyzed, and compared with homogenous and measured data. The results show significance in characterizing the complex fracture networks in near-wellbore models of unconventional fractured reservoirs.

A Framework to Estimate the Key Point Within an Object Based on a Deep Learning Object Detection

Automatic identification of key points within objects is crucial in various application domains. This paper presents a novel framework for accurately estimating the key point within an object by leveraging deep neural network-based object detection. The proposed framework is built upon a training dataset annotated with four non-overlapping bounding boxes, one of which shares a coordinate with the key point. These bounding boxes collectively cover the entire object, enabling automatic annotation if region annotations around the key point exist. The trained object detector is then utilized to generate detection results, which are subsequently post-processed to estimate the key point. To validate the effectiveness of the framework, experiments were conducted using two distinct datasets: cross-sectional images of a parawood log and pupil images. The experimental results demonstrate that our proposed framework surpasses previously proposed approaches in terms of precision, recall, F1-score, and other domain-specific metrics. The improvement in performance can be attributed to the unique annotation strategy and the fusion of object detection and key point estimation within a unified deep learning framework. The contribution of this study lies in introducing a novel framework for closely estimating key points within objects based on deep neural network-based object detection. By leveraging annotated training data and post-processing techniques, our approach achieves superior performance compared to existing methods. This work fills a critical gap in the field by integrating object detection and key point estimation, which has received limited attention in previous research. Our framework provides valuable insights and advancements in key point estimation techniques, offering potential applications in precise object analysis and understanding. Doi: 10.28991/HIJ-2023-04-01-08 Full Text: PDF

An integrated study of core and borehole image data: palaeokarst development in late Permian siliceous dolomites and the structural evolution of the Loppa High from the Gohta discovery well, SW Barents Shelf

Abstract The Gohta discovery well 7120/1-3, drilled on the Loppa High in the SW Barents Shelf in northern Norway encountered a meteoric karst system hosted by the late Permian lower Røye Formation that formed during a period of sub-Triassic exposure. The karst system is preserved as a series of interbedded collapse breccias representing formerly open palaeocaves, matrix-rich breccias that represent palaeocave fills with in situ and reworked stalactites and stalagmites. Layers of ‘Swiss cheese’ texture are interpreted as zones of dissolution in marine-meteoric mixing zones that may have controlled the levels of palaeocave development within the Gohta structure. These other cavities and the matrix of karst breccias were infilled by layered fine doloarenite matrix interpreted as an internal fill generated by collapse. This was followed by a later matrix of dark grey argillaceous mudstone that is interpreted as an external fill that pre-dates the overlying Klappmyss Formation. The karst system has undergone complex early diagenesis that includes extensive dissolution, early leaching of silica, the precipitation of pyrite on internal surfaces and sediment and the precipitation of carbonate and silica as speleothems and vadose cement. A borehole imaging log (BIL) was run across the lower Røye and Triassic Klappmyss formations, including the cored interval that provides a record of inclination and azimuth of the karst fills and in situ Røye Formation. The core provides information about the origin and timing of the different karst fills, and the BIL provides information about their azimuth and inclination. This integrated use of core and BIL data allows the incremental tilting history of the Loppa High structure during exposure to be reconstructed. At present, the Gohta structure has a finite tilt of 5–10° to the SE. The plunge of in situ stalagmites and stalactites suggests that the karst system was initiated while the Røye Formation was slightly tilted to SE. The dip of karst components and the host stratigraphy indicate several phases of incremental tilting during deposition of the doloarenite and argillaceous mudstone karst matrix. There appears to have been a reversal of tilt of the Gohta structure prior to its onlap by the Klappmyss Formation.

Present-Day In Situ Stress Analysis in Shale Reservoir of Haiba Block, Southern Sichuan Basin, South China

Natural gas from shale gas reservoirs has been an important contributor for reserve growth, deliverability construction, and profits growth in natural gas industry in the world. Hydraulic fracturing is commonly required in the shale gas commercial development, and thus understanding the present-day in situ stress field is greatly significant for the hydraulic fracturing and efficient development in shale gas reservoirs. However, there are no systematic investigations on the present-day in situ stress field in the Haiba Block from the Sichuan Basin, South China. In this study, the present-day in situ stress orientations and magnitudes in shale reservoir of Haiba Block are investigated based on the well interpretations from borehole image log and geomechanical modeling. Then, the effects of stresses on hydraulic fracturing, horizontal wells, and natural fracture reactivation were discussed. The results indicate that the horizontal maximum principal stress (SHmax) orientation is mainly in the NE-SW-trending, NW-SE-trending, and WNW-ESE-trending in the Haiba Block. The magnitudes of horizontal maximum and minimum principal stresses are 13.5 MPa~85.5 MPa and 2.8 MPa~31.6 MPa, respectively. In the Haiba Block, the differential stress is generally low in the northern part, which indicates that complex hydraulic fracture networks may be produced. While the natural fractures are generally stable under the present-day in situ stress field. When the increase of pore pressure gradient is about 30 KPa/m, nearly all natural fractures in the Longmaxi Formation may be reactivated. The results can provide the insights into a better understanding of the present-day in situ stress distribution so as to optimize perforation orientation, hydraulic fracturing design, and enhance gas production in shale gas reservoirs.

Evaluation of irreducible water saturation by electrical imaging logging based on capillary pressure approximation theory

One of the most important metrics for evaluating oil and gas reservoirs is irreducible water saturation (Swir). The completion of oil and gas reservoir development tasks, such as fluid identification, productivity prediction, and water-flooded reservoir discrimination, requires the accurate evaluation of Swir. Nuclear magnetic resonance (NMR) logging can reflect the intricate pore structure of reservoirs, so it offers a natural advantage in the evaluation of Swir, but its high measurement cost leads to infrequent use. In geophysical logging, electrical imaging logging can obtain pore size distribution information at a lower cost. Hence, a method based on electrical imaging logging data is proposed to predict Swir. This method not only has a high degree of accuracy but is also cost-effective. First, the pore characteristics of the bound fluid were analyzed with the mercury injection capillary pressure curve. Based on the capillary pressure approximation theory, the reverse cumulative curve of the porosity spectrum was derived. And the physical meaning of its “inflection point” was clarified. Then, the resistivity of the formation containing just irreducible water was computed using the conversion between the core displacement pressure and resistivity. Finally, based on Archie's formula, the Swir at each depth of the reservoir was predicted. By using ultradeep carbonate reservoir logging data from the Yuanba gas field, the model was validated. The results demonstrated that the calculated values using this method agreed with the measured values from the cores. Compared with the core fitting method, the average absolute error is reduced by 2.61%, and the average relative error decreases by 12.0%. If NMR logging information is not present, this method serves as an effective supplement to accurately predict Swir.

Natural fractures characterization by integration of FMI logs, well logs and core data: a case study from the Sarvak Formation (Iran)

Carbonate reservoirs in Iran are the most important and main sources of oil and gas production. Hydrocarbon flow rates from carbonate reservoirs heavily rely on the development of natural fractures. This study focuses on the role of natural fractures on reservoir quality considering the Sarvak carbonate reservoir (southwest Iran) as the second most important oil reservoir of Iran. To identify small-scale fractures around the borehole walls, cores description and image logs were utilized. Due to high cost of coring, lack of orientation and low core recovery in fractured zones indirect methods based on image logs and conventional well logs were exploited for fracture characterizations. For this purpose, a complete set of well data including image logs (FMI), well-log-derived porosity and permeability data together with petrophysical logs were employed. Interpretation of image logs allows different types of natural structures such as open, vuggy, partly-filled and filled fractures, bedding planes and stylolites to be identified. Comparisons between the petrophysical-log and image-log interpretations provide useful relationships with reservoir characteristics. Neutron and sonic logs show a direct relationship with fracture porosity, while the density log displays an inverse correlation with fracture porosity. Neutron-density and neutron-sonic cross-plots show that the dominant lithology of the studied well is limestone with minor fractions of dolomite and shale. Total porosity ranges from 2 to 30%, while the contribution of secondary porosity, on average, is below 3%. Relationships between fracture-frequency diagrams and reservoir permeability show that high permeability zones are well correlated with the high frequencies of open and vuggy fractures and zones that have flowed oil and associated gas in production tests. Natural fracture characterization based on systematic and integrated interpretations of image logs and petrophysical data can play an important role in optimizing field development, resource recovery and production from the Sarvak reservoir. Once calibrated, this method also offers potential as an exploration tool.

A novel approach for fracture porosity estimation of carbonate reservoirs

AbstractThe quality of carbonate reservoirs is linked to their rock properties and surrounding stress settings which can play a vital role in their production optimization and development programs. Imposing various stresses can increase porosity and permeability by creating joints and cracks across the rock mass. Therefore, developing methods to identify and accurately evaluate fractures in carbonate reservoirs is very significant in reservoir characterization. To deal with this necessity, we developed a fracture porosity estimation method using empirical and analytical solutions based on the wireline data considering stress conditions. The proposed methodology was applied to a carbonate reservoir as the case study. As fracture porosity is sensitive to stress, experimental tests were conducted on the core samples using triaxial hydrostatic tests. These tests are needed to simulate reservoir conditions to investigate the relationships between fracture volume fraction and the applied stress. A substantial porosity loss was observed during the hydrostatic test, which can be linked to the crack porosity closure. The reliability of our results was validated by thin section, computed tomography–scan images, velocity deviation method, elastic boundary laws, and image logs. Eventually, we introduced an equation to estimate in situ fracture porosity from the relationship between porosity and effective confining pressure. We verified the repeatability and generality of our proposed methodology using a blind well, and the results indicate a comparable level of accuracy. Our findings are applicable for estimating crack porosity for rock physics modelling purposes of detecting fracture zones in the absence of image logs and core data. Moreover, by calibrating and optimizing the constant parameters in our proposed relationship, one may further estimate crack density in any other given carbonate reservoirs.

Tree log identification using convolutional neural networks

The identification of individual tree logs along the wood procurement chain is a coveted goal within the forest industry. The tracing of logs from the sawmill back to the forest would support the legal and sustainable sourcing of wood, as well as increase the resource efficiency and value of harvested timber. In this work, using a dataset of thousands of Scots pine (Pinus sylvestris L.) log end images displaying varying perspectives, lighting, and aging effects, we develop and assess log identification methods based on deep convolutional neural networks. The estimated rank-1 accuracy of our final model on an independent test set of 99 logs is 84 and 91% when allowing for random rotations of the log ends and when keeping each log at approximately fixed orientation, respectively. We estimate the scaling of these methods up to a template pool size of 493 logs, which reveals a weak dependence of accuracy on pool size for logs at fixed orientation. The deep learning approach gives superior results to a classical local binary pattern method, and appears feasible in practice, assuming that pre-filtering of the log database can be leveraged depending on the use case and properties of the queried log image. We make our dataset publicly available.

Generation of inverse assist features using generative adversarial networks

Adding the assist feature in the optical proximity correction (OPC) procedure is crucial for improving the process window. The rule-based assist feature placement is very fast; however, the resultant process window still requires improvement. The model-based assist feature placement presents a better process window, but its iterative nature makes it extremely time-consuming. The assist features (AFs) that are optimized by using the inverse lithography technique perform best in terms of lithographic metrics such as the Depth of Focus, Mask Error Enhancement Factor, and Normalized Image Log Slope; these features can be added to the objective function. However, the inverse lithography technique is a pixel-level correction method, which is even more time-consuming. Consequently, it is typically used to provide guidance for rule-based AF placement. In this study, we design novel generative adversarial networks (GANs) that can generate AFs to increase the speed of assist feature placement while maintaining relatively high lithographic performance using inverse lithography techniques. The results demonstrate that the proposed generative adversarial network methods are three orders of magnitude faster than the inverse lithography techniques. Additionally, they exhibit lower edge placement errors and process variation bands when compared to the inverse lithography techniques.

Complex genesis of multiperiod fractures in the Middle Triassic Leikoupo Formation in the Pengzhou gas field, western Sichuan Basin, China

The cumulative expression of multistage deformation is complex multiperiod fractures, which are commonly seen in tectonic zones. The Middle Triassic Leikoupo Formation in the western Sichuan Basin Depression, China, is a typical marine carbonate reservoir with natural fractures caused mainly by tectonic movements. According to outcrops, drill cores, image logging, and fluid inclusions, the fracture characteristics, types of natural fractures, and interactions of fractures are determined. In total, 419 natural fractures in 493.2 m of cores from 7 wells are investigated, which are mainly shear and tensile fractures with a small number of weathering generated fractures. Meanwhile, the results of the stable isotope analysis of δ13C and δ18O, as well as the flow fluid inclusion data, reveal four tectonic periods of fractures with different occurrences. Based on the history of regional tectonic evolution, indicating one period of weathering fractures ascribable to stratal uplift and three periods of structural fractures related to the sequential tectonic movements of the Longmenshan fault belt. By analyzing the interaction relationships of fractures, three types of fracture interaction relationships are observed: cutting, restraining, and overlapping. The four stages fractures are chronologically assigned to (1) the early Indosinian N–S trending compression, (2) the late Indosinian NW-SE compression, (3) the middle Yanshanian NE-SE compression, and (4) the early Himalayan E-W compression. The influence of natural fractures on gas migration and well production in marine carbonates is discussed, and indicates that tectonic fractures could provide seepage channels for gas migration and accumulation from near or distant hydrocarbon source rocks into the Middle Triassic Leikoupo Formation. This study utilizes a pragmatic approach for understanding the fracture genesis mechanism in oil and gas field with multiperiod fractures.