Fullbore Formation MicroImager Research Articles

Tectonic fractures induced by strike-slip faulting in intracratonic ultradeep carbonate rocks: Insights from the finite element method and self-adaptive constraints computational model for boundary conditions

Numerical simulations of the paleostress field during a period of tectonic fracture formation and rock failure criteria are used to quantitatively predict the development and occurrence of tectonic fractures induced by the formation of the SB18 fault zone in the Middle Ordovician Yijianfang Formation of the Shunnan area, Tarim Basin, China. The results of acoustic emission experiments, mechanical property measurements, and tectonic fracture occurrence observations obtained from core descriptions and fullbore formation microimager logs are combined with the Andersonian model of faulting and the finite element method, which is widely used for the numerical simulation of stress fields, to investigate the paleotectonic and in situ stress fields via numerical simulation. The quantitative prediction of the opening pressure and opening sequence of tectonic fractures is based on the occurrence of tectonic fracture, numerical simulation of in situ stresses, and coordinate system conversion. The results show that the width of the fracture zone induced by strike-slip faulting is ∼310 m. The degree of fracture development is significantly increased when the Young’s modulus, paleostress difference, and paleostress difference coefficient of the rock are elevated. The current horizontal principal stress is positively correlated with the distance from the fault, and the elevated areal density of the secondary faults causes a clockwise deflection of the horizontal stress direction. SSE-striking shear fractures with orientations ranging from 140° to 150° and two sets of tensional fractures with orientations ranging from −40° to −35° and 55° to 60° are preferentially opened in the water injection development stage of the reservoir. As the horizontal stress difference, horizontal stress difference coefficient, and angle between the maximum horizontal principal stress and a fracture decrease, the fracture opening pressure decreases. At the structural highs (burial depths <6225 m) and lows (burial depths >6225 m), the fracture burial depth is positively and negatively correlated with the opening pressure, respectively. Quantitative prediction of tectonic fracture developmental characteristics, opening pressure, and the opening sequence and investigation of the main factors that control their development can help to identify and support opportunities for hydrocarbon exploration and development of fractured carbonate reservoirs.

DDViT: Advancing lithology identification on FMI image logs through a dual modal transformer model with less information drop

Lithology is an essential topic in oil and gas reservoir studies. Lithological observation lays the foundation for assessing oil and gas prospects and guides future exploration and development. Currently, the prevailing approach in lithological observation heavily depends on the manual analysis of core samples. However, such an approach is highly subjective and time-consuming. With the development of deep learning, some automated deep learning-based methods have been proposed for lithology interpretation from logging curves. However, the Fullbore Formation MicroImager (FMI) image logging, while widely used in the oil field exploration and development process, is occasionally deployed and utilized for lithology identification. In this work, we proposed a Dual-modal Drop-less-information Vision Transformer (DDViT), an FMI image lithology identification model based on transformer architecture. DDViT uses a dual-modal architecture to identify lithology using two different image modalities, namely dynamic FMI images (FMI_DYN) and static FMI images (FMI_STAT). These modalities reflect the local and overall characteristics, respectively. Furthermore, DDViT uses a less-information dropping module to drop the blank band information inherent in the FMI images to make our model more rational and stable. DDViT achieved a 90.81% lithology identification accuracy on Fengxi Well A of the western Qaidam Basin, providing a new approach to lithology identification and demonstrating the great potential of deep learning in geological images.

Blank Strip Filling for Logging Electrical Imaging Based on Multiscale Generative Adversarial Network

The Fullbore Formation Micro Imager (FMI) represents a proficient method for examining subterranean oil and gas deposits. Despite its effectiveness, due to the inherent configuration of the borehole and the logging apparatus, the micro-resistivity imaging tool cannot achieve complete coverage. This limitation manifests as blank regions on the resulting micro-resistivity logging images, thus posing a challenge to obtaining a comprehensive analysis. In order to ensure the accuracy of subsequent interpretation, it is necessary to fill these blank strips. Traditional inpainting methods can only capture surface features of an image, and can only repair simple structures effectively. However, they often fail to produce satisfactory results when it comes to filling in complex images, such as carbonate formations. In order to address the aforementioned issues, we propose a multiscale generative adversarial network-based image inpainting method using U-Net. Firstly, in order to better fill the local texture details of complex well logging images, two discriminators (global and local) are introduced to ensure the global and local consistency of the image; the local discriminator can better focus on the texture features of the image to provide better texture details. Secondly, in response to the problem of feature loss caused by max pooling in U-Net during down-sampling, the convolution, with a stride of two, is used to reduce dimensionality while also enhancing the descriptive ability of the network. Dilated convolution is also used to replace ordinary convolution, and multiscale contextual information is captured by setting different dilation rates. Finally, we introduce residual blocks on the U-Net network in order to address the degradation problem caused by the increase in network depth, thus improving the quality of the filled logging images. The experiment demonstrates that, in contrast to the majority of existing filling algorithms, the proposed method attains superior outcomes when dealing with the images of intricate lithology.

Correction to: Natural fracture characterization and in situ stress orientation analysis using Fullbore Formation Micro Imager (FMI): a case study on the X oil field, Kurdistan Region, Iraq

Correction to: Natural fracture characterization and in situ stress orientation analysis using Fullbore Formation Micro Imager (FMI): a case study on the X oil field, Kurdistan Region, Iraq

Natural fracture characterization and in situ stress orientation analysis using Fullbore Formation Micro Imager (FMI): a case study on the X oil field, Kurdistan Region, Iraq

Natural fracture characterization and in situ stress orientation analysis using Fullbore Formation Micro Imager (FMI): a case study on the X oil field, Kurdistan Region, Iraq

Azimuthal Investigation of a Fractured Carbonate Reservoir

Summary Oil production and enhanced oil recovery in carbonate reservoirs in Abu Dhabi, UAE, are largely affected by fracture systems that control the fluid path and the permeability of reservoirs. Most fracture properties, such as fracture orientations and density, are obtained by interpreting petrophysical data acquired at the wellbores, whereas fracture properties between wells are typically derived from nonzero offset seismic data. However, deriving fracture properties from seismic data is challenging, as it requires a robust methodology and a careful seismic processing procedure. In the current case study, we used the azimuthal amplitude vs. offset (AVAz) method on 3D seismic data acquired in onshore Abu Dhabi, to generate maps of fracture orientation and density in a carbonate reservoir. A sophisticated processing series was carefully performed to increase signal-to-noise ratio (SNR) and preserve seismic amplitudes. The main parameters controlling the AVAz method were investigated and optimized before being applied to the 3D seismic data. The reservoir has a high fracture density in the lower regions, but a low fracture density in the upper parts, indicating a weaker anisotropy. The resulting dominant fracture directions span from north-northwest/south-southwest to north-northeast/south-southwest, as well as from northwest/southeast to east/west, which is consistent with the primary fracture orientations determined from the interpretation of fullbore formation microimager (FMI) data acquired at well locations. These fracture systems are the result of the Late Cretaceous obduction of the Semail ophiolite, which was oriented east/west and northeast/southwest, followed by the south/north to southwest/northeast trending Late Oligocene-Miocene continent-continent collision of the Arabian and Central Iran plates along the Zagros orogenic front.

The effects of planar structures on reservoir quality of Triassic Kangan formation in the central Persian Gulf, an integrated approach

Planar structures including stylolites, solution seams, dense streaks, bedding and cross-bedding surfaces, and fractures of carbonate Early Triassic Kangan Formation were evaluated in the central Persian Gulf. Core X-ray computed tomography (CT), Fullbore Formation Micro-Imager (FMI) log, and cores were used to detect the structures. Furthermore, conventional borehole logging data, routine core analysis, and petrographic thin sections were employed to assess the reservoir properties. Stereographic projections demonstrated that the reservoir has two sets of planar structures. The first group contains shallowly-dipping structures, consisting of stylolites, solution seams, dense streaks, bedding and cross-bedding surfaces. These structures have been created by sedimentary and diagenetic processes. The other set includes deformation-related structures that are steeply-dipping and occurred scarcely, like fractures. Spearman correlation coefficients between the frequency of each planar structure and reservoir characteristics (porosity and permeability) were calculated to reveal the numerical relationship between the parameters. The significant correlation coefficients indicate that stylolites, solution seams, and filled tension gashes diminish reservoir quality while bedding and cross-bedding surfaces have enhanced reservoir characteristics. The strongest correlation was observed as a strong negative relationship between the frequency of stylolites and permeability in K2 reservoir unit. This study implies that sedimentary and diagenetic factors are more effective in controlling the reservoir quality than deformation factors in the studied formation. The present work also indicates that each used method has unique advantages and disadvantages. Therefore, simultaneous utilization of the methods to investigate planar structures would have the best efficiency.

Multi-Factor Evaluation of Deep Karst Dolomite Reservoir Based on Paleogeomorphological Reconstruction, a Case Study From the 4th Member of the Dengying Formation in the Central Sichuan Basin, China

The evaluation of reservoirs is of great importance in exploration practices, and reservoir distribution is dependent on multiple geological factors. The carbonate platform of the fourth member (Z2dn4) of the Dengying Formation (Z2dn) in the Gaoshiti-Moxi area (GMA) was uplifted above sea level during episode II of the Tongwan movement and underwent prolonged karstification by meteoric freshwater in the terminal Sinian, leading to a strong heterogeneity in reservoirs. Paleogeomorphology reflects hydraulic gradients that can affect the intensities of surface karstification and may be approximated by terrain slope gradients. Karst products (especially solution vugs and caverns) exist prevailingly in the Z2dn4; their development mirrors the extents of internal dissolution. Based on paleogeomorphological reconstruction using the elevation method, the slope angles of single boreholes were calculated through the digital elevation model (DEM). In accordance with single-borewell Fullbore Formation MicroImager (FMI) logging data, four electrofacies (host rock, vug, fracture, and cave) were identified in boreholes possessing FMI data. The identified electrofacies were matched with corresponding conventional logging curves to obtain the training data. A model generalized for other boreholes without FMI data was established with the random forest algorithm and the thicknesses of the four electrofacies in each borehole were determined to characterize the extent of karstification. Slope gradients and electrofacies thicknesses, together with multiple physical parameters of reservoirs in boreholes, were utilized for factor analysis. Four factors were obtained and fused into one comprehensive score based on their ratios of variance proportions. The favorability of reservoirs was described by the comprehensive scores of each borehole. These analyses showed that the most advantageous reservoirs are distributed in the vicinity of the platform margin in the west of the GMA, where they enjoy several benefits. Deposition of porous mound-shoal complexes occurs predominantly in the platform margin where large-scale caves are more developed in the mixing karst zone of seawater and freshwater. Meanwhile, the transmeridional lateral migration of hydrocarbons from the regional hydrocarbon-generating center abutting the west of the GMA contributes to earlier entrapment and accumulation in the mound-shoal complexes in the platform margin.

An Integrated Approach of Numerical Well Test for Well Intersecting Fractures Based on FMI Image

Abstract Fluid flow is strongly affected by fractures in unconventional reservoirs. It is essential to deeply understand the flow characteristics with fractures for improving the production and efficiency of unconventional reservoir exploitation. The purpose of this work is to develop an accurate numerical model to evaluate the transient-pressure response for well intersecting fractures. The meshes generated from Fullbore Formation Micro-Imager (FMI) images ensure an efficient numerical description of the geometries for fractures and interlayers. The numerical simulation is implemented by an inhouse finite element method-based code and benchmarked with drill stem test (DST) data. The results show that three flow regimes appear in the reservoir with fractures within the test period: wellbore afterflow, pseudolinear flow, and radial flow. In contrast, only the wellbore afterflow and radial flow appear for the wells without fractures. The results also reveal that fractures dominate the flow near the wellbore. Verification and application of the model show the practicability of the integrated approach for investigating the transient-pressure behaviors in the unconventional reservoir.

A novel triple-porosity model for fractured-vuggy reservoirs based on Maxwell-Garnett mixing rule

Under the new energy pattern, the petrophysical properties of carbonate reservoirs are still the research focus in the petroleum industry. Compared with conventional reservoirs, the calculation of water saturation is more complicated for carbonate reservoirs. One of the main challenges is that the accurate calculation of the porosity exponent of the reservoirs is influenced by the development of fractures and vugs. The existing triple-porosity model provides a way to calculate the porosity exponents; however, the existing model still has some problems: (1) The conduction theory adopted to establish the model varies from the actual conductivity process of the reservoir; (2) The model is deduced from the effective medium theory and regional empirical formula without considering the fracture shapes, thus it is not applicable for the carbonate reservoirs with fractures developed. Therefore, this paper proposed a novel triple-porosity model to calculate the porosity exponents by applying the Maxwell-Garnett mixing rule to the fractured-vuggy reservoir. This novel model can calculate the porosity exponents of reservoirs with the joint development of the vugs (non-connected vugs), fractures (fractures and connected vugs), and matrix pores. From the results of the novel model, the more developed the vugs, the greater the porosity exponents, and the more developed the fractures, the smaller the porosity exponent. Therefore, the porosity exponents of the reservoir can reflect the combined influence of the vugs, fractures and matrix pores. In order to effectively calculate the water saturation through this model, a method based on the binary processing of the Full-bore Formation Micro-Imager (FMI) logs was further proposed to calculate the vug porosity and fracture porosity. The field application demonstrated that the novel triple-porosity model can accurately calculate the water saturation of the fractured-vuggy reservoirs and provide guidance to the actual production.

Integrated Fracture Characterization of Thamama Reservoirs in Abu Dhabi Oil Field, United Arab Emirates

Summary Volumetric maximum curvature attribute computed from 3D ocean bottom cable (OBC) seismic data, production logging tool (PLT), inorganic chemical tracer data, and fractures observed from core and full-bore formation microimager (FMI) logs were integrated to characterize fractured carbonate reservoirs of an offshore oil field in Abu Dhabi, United Arab Emirates (UAE). The extracted maximum curvature anomalies are predominantly orientated in NNE-SSW and NE-SW, a trend perpendicular to the dominant fault direction in the oil field and similar to the dominant strike directions of fractures measured from core data and FMI logs. Because the fracture strike directions of well data mimic the strike directions of curvature anomalies at corresponding reservoir levels, we interpreted the maximum curvature anomalies to represent dilatational fractured zones or fracture corridors. Integration of dynamic data, such as PLT and chemical tracers, and maximum curvature anomalies demonstrate that the inferred fracture zones can determine water breakthroughs as well as inter- and intrareservoir communications. As a result, this study highlights possible fracture zones and their internal architecture, as well as their potential flow capabilities. These results play a key role in reservoir management and monitoring of water movement through structural pathways.

Fracture characteristics and logging identification of lacustrine shale in the Jiyang Depression, Bohai Bay Basin, Eastern China

Fracture has a vital effect on the storage and seepage ability of oil and gas in shale reservoirs, and its effective identification and evaluation is of great significance for shale oil and gas development. To analyze and evaluate fracture development characteristics in the lower sub-member of the third member of the Eocene Shahejie Formation (Es3L) and the upper sub-member of the fourth member of the Eocene Shahejie Formation (Es4U) in the Jiyang Depression, Bohai Bay Basin, core observations, thin sections, field emission scanning electron microscopy (FE-SEM), and well logging were performed. After data analysis, fracture types in the study area were characterized, relationships between shale oil types and shale oil production were discussed, and a new method was proposed to identify fractures using only conventional logging curves by combining discrete wavelet transform (DWT) and box fractal dimension with sliding window approach (SW box fractal dimension). Our results indicated that the fracture types according to geologic genesis are structural fractures (structural tension fractures, structural shear fractures, and structural tension-shear fractures), non-structural fractures (abnormal pressure fractures, diagenetic contraction fractures, bedding fractures, and dissolution fractures), and organic matter-related fractures. A close relationship occurs involving the types of shale oil and shale oil production, and fractured shale oil usually has the highest initial production. The fracture identification method using the DWT and SW box fractal dimension has good effects, and its accuracy is verified by Fullbore Formation MicroImager (FMI) logging in L69 well. Two high-production wells of shale oil in the study area (wells FY1 and Y187) were used to identify fracture development sections using the DWT and SW box fractal dimension, and excellent application results were obtained. In general, it is an efficient way to fully evaluate fracture development sections in shale reservoirs in logging profiles, and also provides new ideas for the fracture identification method using conventional logging curves in other shale oil regions.

Multi-scale evaluation of fractured carbonate reservoir and its implication to sweet-spot optimization: A case study of Tazhong oilfield, Central Tarim Basin, China

Ordovician limestone and Cambrian dolomite are the main oil and gas producing layers in eastern Tazhong field, Tarim basin. Industrial oil flow has been obtained from drilling in this zone, proving that the Lower Paleozoic strata is important for oil and gas exploration and development. However, the main controlling factors and distribution of high-quality reservoirs remain unclear. Based on the logging constrained seismic inversion , FMI (Fullbore Formation MicroImager) log interpretation and core analysis of six wells, the main controlling factors of Paleozoic carbonate reservoirs in the study area were investigated. The results reveal that the two buried cuestas control the distribution of the Cambrian and Ordovician strata, the ratio of mudstone in north buried cuesta (NBC) is more than that in south buried cuesta (SBC), and the average porosity of ▪3xq dolomite formation is more than that of O1−2y limestone formation. FMI logging interpretation results show that fracture density of well TZ-1 is significantly higher than that of well TZ-2, combined with core observation and microscopic analysis we can believe that reconstructed dolomite reservoir has developed dissolution pores and vugs. By the means of seismic impedance reconstruction, the most favorable production areas, so-called sweet-spots, are karst residual mounds that formed independent small anticlinal high points and have been depicted. Finally, total 28 traps in the Cambrian–Ordovician​ carbonate buried hill are characterized, covering an area of 66.4 km2. 17 anticline traps with an area of 26.9 km2 in dolomite reservoirs are optimized to be the next exploration targets.

The impact of geomechanical units (GMUs) classification on reducing the uncertainty of wellbore stability analysis and safe mud window design

The current study proposed an improved approach for application of Geomechanical Units (GMUs) classification in reducing the uncertainty of wellbore stability models. For this purpose, the optimal drilling direction and safe mud window were modeled in the Iranian Offshore oilfield, Persian Gulf basin. Two main normal faults created a graben with three geomechanical sectors in the study area including northern, middle and southern sectors. The middle sector, which is under high compression, is the main target of this study. A set of well logs and Fullbore Formation Micro Imager (FMI) data associated with the rock mechanical tests including Uniaxial Compressive Strength (UCS), Triaxial Compressive Strength (TCS) and ultrasonic results were used to establish and tune the geomechanical models. The dynamic rock elastic moduli including UCS, Poisson's ratio, Young's modulus, shear modulus and bulk modulus were estimated from well logs data. Through appropriate correlations between well logs and laboratory results, the dynamic modules were converted to static data. Five geomechanical units were obtained based on the classification of rock elastic moduli by using multi-resolution graph-based clustering.The interpretation of FMI logs and their incorporation in the geomechanical models showed that most safe drilling direction is in the 120° azimuth which is parallel to the direction of minimum horizontal stress, σh (NW-SE direction). Higher mud weight is expected at N030E azimuth to overcome collapse pressure, which is the worst drilling direction, σH (NE-SW direction). Wellbore inclination more than 60° angle is not recommended for formations comprising of GMU E and partially GMU D (mainly shales and clayey limestones). The results of this study showed that GMUs classification is an effective way of updating the wellbore stability models and reducing the uncertainty of safe mud window design.

Fluid flow and fault-related subsurface fractures in slate and metasandstone formations: A case study of the Jentse Geothermal Area, Taiwan

Permeable structures associated with faults are commonly treated as geothermal fluid conduits in most tight geothermal reservoirs. However, the properties of permeable structures within fault zones remain unclear due to the lack of subsurface geological data, e.g., the geothermal systems in the tight slate and metasandstone formations in Northeastern Taiwan. This study presented standard open-hole and Fullbore Formation MicroImager (FMI) logs acquired in the 8.5-inch-diameter section of the JT-3 well (800–1475 m measured depth) in the Jentse geothermal area, Taiwan, to identify the subsurface fracture structures and the possible pathway of fluid flow. Using open-hole log data, we generate a lithology interpretation for the borehole and model the associated effective porosity. Based on the FMI images, four types of natural open fractures, two types of natural sealed fractures, and drilling-induced tensile fractures were identified. Integration of the lithological model, the effective porosity, and the types of fractures reveals one major permeable fault system comprising three permeable fault zones. The fault system is composed of both permeable fault cores marked by porous fault breccia and damage zones characterized by a large number of open-fracture planes. The static borehole temperature log also shows deflections in these interpreted permeable fractures zone. Deflections in these fracture zones that, based on petrophysical and borehole image logs, are interpreted as permeable. According to the orientations of the bed boundaries and fault planes obtained from FMI images, the fault system may have an orientation of N50–70 °E and dips 70–90˚ to the NW with a width of around 116 m. This study illustrates how subsurface structures control geothermal conduits. The concept and workflow of this study may be useful for other fault-controlled geothermal areas in Taiwan.

Vug and fracture characterization and gas production prediction by fractals: Carbonate reservoir of the Longwangmiao Formation in the Moxi-Gaoshiti area, Sichuan Basin

A comprehensive knowledge of the development and connectivity of fractures and vugs in carbonate reservoirs plays a key role in reservoir evaluation, ultimately affecting the gas prediction of this kind of heterogeneous reservoir. The carbonate reservoirs with fractures and vugs that are well developed in the Longwangmiao Formation, Sichuan Basin are selected as a research target, with the fractal dimension calculated from the full-bore formation microimager (FMI) image proposed to characterize the fractures and vugs. For this purpose, the multipoint statistics algorithm is first used to reconstruct a high-resolution FMI image of the full borehole wall. And then, the maximum class-variance method (the Otsu method) realizes the automatic threshold segmentation of the FMI image and acquisition of the binary image, which accurately characterizes the fractures and vugs. Finally, the fractal dimension is calculated by the box dimension algorithm, with its small value difference enlarged to obtain a new fractal parameter ([Formula: see text]). The fractal dimensions for four different kinds of reservoirs, including eight subdivided models of vugs and fractures, show that the fractal dimension can characterize the development and the connectivity of fractures and vugs comprehensively. That is, the more developed that the fractures and vugs are, the better the connectivity will be, and simultaneously the smaller that the values of the fractal dimensions are. The fractal dimension is first applied to the gas production prediction by means of constructing a new parameter ([Formula: see text]) defined as a multiple of the effective thickness ([Formula: see text]), porosity (Por), and fractal dimension ([Formula: see text]). The field examples illustrate that the fractal dimensions can effectively characterize the fractures and vugs in the heterogeneous carbonate reservoir and predict its gas production. In summary, the fractals expand the characterization method for the vugs and fractures in carbonate reservoirs and extend its new application in gas production prediction.

Fracture characteristics of Lower Carboniferous carbonates in northern Belgium based on FMI log analyses

AbstractRecently drilled geothermal boreholes in Mol, northern Belgium, provide new information on the Lower Carboniferous carbonates in the Campine–Brabant Basin. Because of low primary porosity, fractures in these limestones and dolostones are of major importance for reservoir permeability. The Fullbore Formation MicroImager (FMI) log of the MOL-GT-01 borehole enabled interpretation of bed boundaries and fractures in the subsurface. Relationships between the frequency of these fractures and bed thickness, lithology variations and the presence of faults were explored. The results show that thick beds contain relatively few fractures and thin beds relatively many. Except for lower values in shaly intervals, the fracture frequency (number per metre) is largely independent of lithology. Zones with substantial changes in the structural dip (called a cusp) and/or azimuth of bed boundaries were identified. The clearest cusp is present at a depth of 3284 m. Since the presence of a normal fault is most likely regarding the local and regional geology, this cusp likely resembles a fault-tip fold of a WSW-ward dipping normal fault with an inclination of at least 54°. It is uncertain whether the borehole crossed the fault itself or only a monocline on top of it. Fracture frequency is increased in the vicinity of the interpreted possible faults. Up to a vertical distance ofc.45 m from the faults, the mean fracture frequency is higher than in a non-faulted zone with similar lithology. However, frequency differences between these faulted and non-faulted zones are mostly insignificant, so no clear damage zones are present.

Azimuthal investigation of compressional seismic-wave attenuation in a fractured reservoir

Three-dimensional vertical seismic profiling data acquired from an oilfield located in Abu Dhabi, United Arab Emirates, were used to obtain a high-resolution multioffset azimuthal estimate of compressional seismic wave attenuation. On the basis of the assumption that the fracture strike corresponds to the azimuthal direction [Formula: see text] at which the attenuation is minimized, fracture orientations were obtained in three reservoir units. Two approaches were used to determine [Formula: see text]: first from the variation of the absolute attenuation [Formula: see text] with the azimuth and second from the variation of the relative attenuation [Formula: see text] with the azimuth. The rose diagrams of [Formula: see text] estimated from the [Formula: see text] variation indicated better agreement with those showing the strikes of open and cemented fractures obtained from core interpretation than with either of those showing the two types of fractures separately. However, the rose diagrams of [Formula: see text] estimated from the variation of [Formula: see text] were more similar to those showing the strikes of open fractures obtained from core and Fullbore Formation Microimager data. This observation can be explained by the fact that in the first approach, all types of fractures contribute to the scattering and fluid-related mechanisms of [Formula: see text]. However, in the second approach, [Formula: see text] is obtained from a least-squares fitting of the variation of [Formula: see text] with the azimuth, which is based on the squirt flow mechanism that is caused by the movement of fluid between grain pores and fractures. Therefore, a comparison of the orientations obtained using these two approaches can be an efficient way to separately determine the orientations of open and cemented fractures.

Extraction and characterization of faults and fractures from 3D VSP data in a carbonate reservoir: A workflow

We present a workflow for the extraction and characterization of fractures and faults using a Reverse Time Migrated (RTM) volume from 3D Vertical Seismic Profile data (3D VSP) acquired in an oilfield offshore Abu Dhabi in the United Arab Emirates. The workflow consists of: preconditioning of the input RTM volume, which involves removal of acquisition footprints; extraction of faults and fractures using a semblance based discontinuity attribute; binary filtering and clustering for characterization and interpretation using prior geological information, as well as removals of unwanted features such as those related to stratigraphy; and finally interpretation. Complex networks of lineaments were extracted after application of the workflow. The location of lineaments with length greater than 200 m and orientated WNW-ESE to NW-SE correlates with a known flower structure which has a trend similar to that of the Proterozoic Najd Fault System that cut the Arabian Peninsula. Lineaments with strike directions ENE-WSW and NE-SW are interpreted to be related to reactivation of basement faults and correspond to the Hormuz Salt basin's major trend in the Arabian Gulf. Dominant strike directions of lineaments at three reservoir levels correlate with dominant strike directions of interpreted fractures from Fullbore Formation Microimager (FMI) and core data; thus implying that they are likely related to fractures or fracture corridors. Lineaments with orientation NNE-SSW correlate with closed fractures while lineaments with orientation NNW-SSE correlate with open fractures. Zones with relatively high fracture intensity are generally located north and north-west of the VSP well in the reservoir zones. The good correlation of the results with interpreted fractures from core and FMI data shows the robustness of the workflow and gives confidence to the results.

Petrophysical Evaluation of a Severely Heterogeneous Carbonate Reservoir; Electrical Image Logs Usage in Porosity Estimation

Image logs have higher resolution than conventional logs and it makes them powerful tools for detailed reservoir characterization and modeling. Hence, thin beds, which are not detectable using conventional logs, can be characterized by image log data. The present study focuses on the Permian-Triassic carbonate reservoirs of Dalan and Kangan formations in one of the gas fields in southern Iran. In this study, the reservoir porosity was estimated using Fullbore Formation Microimager (FMI) image log. Then, the results were compared and validated with the core data. Porosity was estimated as 2-dimentional image by rescaling the FMI image log with Micro-Spherical Focused Log (MSFL). The image log-derived porosity was then compared with conventional logs-derived and core porosities. The image log-derived porosity is in good agreement with the core data. In this paper, a procedure was introduced which can be used to recognize very narrow pay layers (thickness in centimeters). This work is very important for identifying the proper perforation intervals in heterogeneous reservoirs.