Image Logs Research Articles

Developing a novel permeability prediction method for tight carbonate reservoirs using borehole electrical image logging

Predicting permeability accurately is crucial for effective hydrocarbon extraction, but the intricate pore structures of tight carbonates resulting from sedimentation, diagenesis, and tectonic activity present significant challenges. Based on borehole electrical image logging and fractal theory, we develop a method to calculate the fractal dimension of the porosity spectrum to characterize the complexity of the pore structure of the reservoir. Fractal features of the porosity spectra are studied, and fractal parameters are calculated, such as the left ([Formula: see text]), middle ([Formula: see text]), and right fractal dimensions ([Formula: see text]). A permeability prediction model is developed based on fractal parameters by investigating the linear relationship between fractal parameters and core permeability. The results indicate that [Formula: see text] and permeability have a coefficient of determination ([Formula: see text]) of 0.78, whereas [Formula: see text] between porosity and permeability is only 0.03. The [Formula: see text] and [Formula: see text] have little correlation with core permeability. The prediction results of the [Formula: see text]-based permeability model are in good agreement with the experimental data with Pearson product-moment correlation coefficient of 0.93 in the field applications. Our findings suggest that large pores primarily contribute to the permeability of tight carbonates because [Formula: see text] corresponds to the macroporous part of the porosity spectrum. This study enhances our understanding of the factors that influence permeability and provides a useful tool for predicting permeability in tight carbonate reservoirs.

Non-stationary inversion of seismic data for fracture compliances in azimuthally anisotropic mediag

Fractures and tectonic settings cause azimuthal anisotropy in reservoirs. Recognizing the fracture model from the seismic data is a useful tool for identifying the productive zone in the reservoirs. We applied azimuthal velocity analysis in seismic processing to improve image quality and to estimate anisotropic model parameters. Using azimuthal residual moveout analysis, we predicted the direction of azimuthal anisotropy in the reservoir, and found that the results are consistent with fracture orientations obtained from the image logs in the reservoirs. Bayes’ theorem, and a cascaded procedure in least-squares inversion, matching observed amplitudes to linearized Zoeppritz equations, were used to estimate the elastic moduli in a first step and normal and tangential fracture weaknesses in a second step. We used laboratory experiments on core samples to validate the first step inversion results. We found that the propagation wavelet varied in space and reflection time, and so a library of extracted wavelets in the time-frequency domain was used for seismic inversion. Maps of computed fracture fluid index and the estimated fracture weaknesses help to visualize the role of fractures in reservoir productivity and revealed a consistency with the seismic peak frequency attribute in identifying zones of highly compliant fracture fill. The estimated fracture model demonstrates a good fit with the fractures seen in the available core samples and implies that the fracture fluid index is a useful attribute for determining the productive zones in the reservoir.

Prediction and Application of Drilling-Induced Fracture Occurrences under Different Stress Regimes

Identifying and categorizing drilling-induced fractures is pivotal for understanding the mechanisms underlying wellbore instability, drilling fluid loss, and assessing reservoirs using imaging logging data. This study employs a linear elastic stress model around the wellbore, coupled with a tensile failure criterion, to establish a predictive framework for the orientation of drilling-induced fractures. It investigates how engineering parameters like wellbore trajectory and bottomhole pressure influence the distribution of principal stresses around the wellbore, as well as the angle and orientation of drilling-induced fractures relative to the wellbore axis, across various faulting scenarios. The results indicate that drilling-induced fractures exhibit structured arrangements and consistent patterns, often appearing at approximately 180° symmetric intervals and descending in similar orientations. This provides a theoretical basis for their systematic identification and classification. Under different stress conditions, these fractures can manifest as feather-like shapes, “J”-shaped, or transitional states between feather-like and “J”-shaped orientations, as well as “V”-shaped or “M”-shaped orientations. Accurate detection and classification of these fractures are essential for interpreting effective fractures, conducting thorough reservoir evaluations, and predicting appropriate drilling fluid densities to mitigate the wellbore failure risk. Moreover, this knowledge aids in effectively determining the magnitude and direction of in situ stress inversion.

Reconstructing the Zama (Mexico) discovery source to sink story, Part I; detrital zircon U–Pb and (U‐Th)/He provenance analysis and implications for sediment source terranes

AbstractThe Zama discovery was identified off the coast of Tabasco, Mexico, in the Sureste Basin of the Gulf of Mexico and is hosted in a three‐way closure in the Upper Miocene. This study conducted a detailed detrital zircon (DZ) U–Pb and (U‐Th)/He provenance analyses on samples from sandstone reservoirs in the Zama‐3 and Zama‐2ST1 wells. A total of 22 sandstone samples (11 from each well) were collected for DZ U–Pb and (U‐Th)/He dating from different reservoir zones, testing the hypothesis that different zones were whether originally derived from varied sedimentary source terranes and associated transport pathways to the Zama mini‐basin depositional site. Additional objectives include determination of maximum depositional ages, reconstruction of paleofluvial systems, and exploring the temporal evolution of the drainage region and hinterland tectonics. The DZ U–Pb age spectra from both Zama wells have remarkably homogenous DZ signatures with very similar DZ age modes and modal percentages, displaying dominant Permian/Chiapas Batholith (ca. 35%–45%), Mesoproterozoic/Oaxaquian (ca. 20%–35%), Early Palaeozoic/Acatlán (ca. 8%–20%), and Cenozoic magmatic arc (ca. 15%–25%) age modes, as well as some subsidiary (<5%) early Proterozoic/Archean and Early Cretaceous DZ age components, linked to recycled lower Palaeozoic strata and the Guerrero Terrane and Alisitos arc, respectively. Despite differences in paleocurrent directions, deduced from image logs, there are no systematic differences in DZ spectra, indicating a consistent sediment provenance and no changes in source area. All Zama samples analysed in the study are characterized by abundant syn‐depositional Late Miocene DZ grains, clustering between 8.6 and 10.2 Ma, corroborating a Tortonian (Late Miocene) depositional age, and yield rapid sediment accumulation rates of ca. 200 m in <1.4 Ma (13 m/Myr). Doubled zircon U–Pb and (U‐Th)/He age pairs are indicative of recycling of early Mesozoic rift strata and Paleogene and younger Chiapas basement. These new DZ U–Pb and (U‐Th)/He data have a nearly invariant Tortonian sediment provenance that is similar to the modern Grijalva River flowing generally northward out of the Chiapas highlands. The paleo‐Grijalva drainage, providing sediment to the Late Miocene Zama mini‐basin, was likely drastically larger than the present catchment as it involved 10 Ma plutonic sources that were subsequently downfaulted along the Pacific coast in the latest Miocene. Importantly, DZ U–Pb age components are consistent with Oaxaquia, early Acatlán, and Guerrero/Alisitos signatures and point to sourcing from the Chortis block during its tectonic eastward translation. Such a scenario would allow for a substantially larger Miocene paleo‐drainage that would have encompassed both Chiapas and portions of Chortis. The Miocene tectonic translation of Chortis and erosion of a large and tectonically active hinterland would also reconcile the dramatically larger Middle to Late Miocene sediment supply, funnelling a large influx of sediment into the southern Gulf of Mexico. Rapid Late Miocene sediment accumulation in the salt‐defined Zama mini‐basin must have involved sustained sediment flux via the paleo‐Grijalva drainage and was likely facilitated and focused by continued salt deflation due to sediment loading, as described in Part II. Thus, our work provides new scientific insights into one of the largest hydrocarbon discoveries in Mexico in recent years.

Dipole acoustic remote detection (ARD) logging and its application in fracture-cave reservoir

Abstract Oil and gas from deep reservoirs are mostly enriched in the fracture-cave reservoirs. For this reason, fine evaluation of large-scale fracture-cave and effective detection of small scale fracture-cave are the key issues to be solved in the exploration of fracture-cave type carbonate reservoirs. The acoustic remote detection logging technology is based on acoustic reflection method to continuously image the formation around the well. The cross dipole array sonic data can be processed to image geological anomalies within a range of about 20 meters outside the well. Dipole S wave remote detection has the remarkable advantages of low emission frequency and larger investigation depth, but it has 180 degrees’ azimuthal ambiguity. This study is based on previously developed far field dipole S wave remote detection tool, finite difference is performed on formation models with and without are obtained for representative fracture-cave formations and remote detection processing and interpretation software is updated. These are applied on a well in the northwestern area. Through the comprehensive analysis of remote logging, conventional logging, electrical imaging logging and seismic data of the fracture-cave geological anomalies, a fine picture of the morphology and development of the geological anomalies from the near wellbore to the far end is formed

Characteristics and effectiveness of deep and ultradeep tight sandstone fractures: Insights from geologic and geophysical data analysis

Effective natural fractures are those that contribute to reservoir storage and conductivity. In this study, the effectiveness of fractures in deep and ultradeep reservoirs (depths > 6 km) is evaluated by using geophysical image logs, cores, microstructures, mechanical tests, and geologic evidence of the tectonic context (including current in situ stress) and sedimentary faces and diagenesis. Intraformational open-mode fractures are the most common fracture type in this tectonically active region, and their effectiveness is affected by the coupling between past tectonic activity, in situ stress, and chemical reactions such as mineral precipitation or dissolution (diagenesis). Our results show that the effectiveness of fractures is mainly related to the aperture and filling, and fractures formed by early tectonic movement are more likely to be filled by minerals, reducing their effectiveness. Strata near orogenic belts in strongly cemented, tight diagenetic facies exhibit a greater abundance of mineral-filled fractures, whereas dissolution increases the fracture apertures, produces secondary pores in host rocks, and roughens the fracture walls. The effective normal stress acting on the fracture surface decreases when the fracture is parallel to the maximum horizontal stress component, so the fracture has a large aperture and, therefore, is more effective. The results of our laboratory measurements reveal that the contribution of fractures to the reservoir space is limited, and the reservoir space provided by fractures accounts for only 13% of all types of reservoir space, whereas the presence of fractures increases reservoir permeability by 1–2 orders of magnitude. Fractures improve the effectiveness of the reservoir by connecting the dispersed pores in the reservoir matrix. Fractures with a low angle to the maximum horizontal stress component have greater apertures and permeabilities and are the main channels for fluid flow.

Physical characterization of mine goafs using high-resolution seismic cross-hole tomography via an adjoint method

Mine goafs often cause severe ground settlement and collapse, posing significant endangers to the safety of buildings and engineering constructions. Quantitatively detecting the spatial distribution and physical characteristics of goafs has always been challenging. To evaluate the potential threat of a fluorite mine goaf on a proposed expressway, we inverted cross-hole dataset to image the P-wave velocities between boreholes using a newly developed Eikonal equation based adjoint-state traveltime tomography method (ATTOMO). Independent comprehensive geophysical prospecting, including core analysis, borehole optical televiewer imaging and ultrasonic wave logging, indicates that our tomographic results at the central section could discern anomalies on a scale of 1 m or even smaller and detects velocity variations at a scale of 100–200 m/s. Our results show that the mine goaf is distributed in a northeastward trend with a width of 20–30 m, consistent with the exploiting features of the fluorite mine. The goaf is located approximately 20 m away from the bridge site, where only a small-scale goaf tunnel with dimensions of [Formula: see text] m was found at depths of 18–19.5 m. Our results suggest that the safety of the proposed expressway would not be significantly affected by the goaf, and thus no design changes are required.

Deep-learning-based natural fracture identification method through seismic multi-attribute data: a case study from the Bozi-Dabei area of the Kuqa Basin, China

Fractures play a crucial role in tight sandstone gas reservoirs with low permeability and low effective porosity. If open, they not only significantly increase the permeability of the reservoir but also serve as channels connecting the storage space. Among numerous fracture identification methods, seismic data provide unique advantages for fracture identification owing to the provision of three-dimensional information between wells. How to accurately identify the development of fractures in geological bodies between wells using seismic data is a major challenge. In this study, a tight sandstone gas reservoir in the Kuqa Basin (China) was used as an example for identifying reservoir fractures using deep-learning-based method. First, a feasibility analysis is necessary. Intersection analysis between the fracture density and seismic attributes (the characteristics of frequency, amplitude, phase, and other aspects of seismic signals) indicates that there is a correlation between the two when the fracture density exceeds a certain degree. The development of fractures is closely related to the lithology and structure, indirectly affecting differences in seismic attributes. This indicates that the use of seismic attributes for fracture identification is feasible and reasonable. Subsequently, the effective fracture density data obtained from imaging logging were used as label data, and the optimized seismic attribute near the well data were used as feature data to construct a fracture identification sample dataset. Based on a feed-forward neural network algorithm combined with natural fracture density and effectiveness control factor constraints, a trained identification model was obtained. The identification model was applied to seismic multi-attribute data for the entire work area. Finally, the accuracy of the results from the training, testing, and validation datasets were used to determine the effectiveness of the method. The relationship between the fracture identification results and the location of the fractures in the target reservoir was used to determine the reasonableness of the results. The results indicate that there is a certain relationship between multiple seismic attributes and fracture development, which can be established using deep learning models. Furthermore, the deep-learning-based seismic data fracture identification method can effectively identify fractures in the three-dimensional space of reservoirs.

Polyaxial failure criteria for in situ stress analysis using borehole breakouts: Review of existing methods and development of an empirical alternative

Analysis of compressive wellbore failure, or breakouts, is one of the primary methods of constraining the maximum horizontal stress in deep boreholes. To estimate stress using the observation of breakouts, one needs to measure the breakout width from image logs and use a failure theory to predict the stress that led to the development of the measured breakout. Most commonly, Mohr–Coulomb failure criterion has been used which disregards the influence of intermediate stress on strength. Hence, various polyaxial criteria have been proposed to include this effect. Here, we first review some selected polyaxial criteria: Drucker–Prager, Mogi, Modified Wiebols–Cook, and Modified Lade, and we conclude that their application in breakout analysis may be cumbersome and often unreliable. One reason for these problems is that the criteria are defined using stress invariants, while the stress estimation is most easily performed and analyzed in the principal stress space. Therefore, an alternative is to define the polyaxial criterion as a simple relation between maximum and intermediate stresses. We propose to define such an empirical criterion as a second order polynomial which fits trends observed in polyaxial laboratory strength data. Such approach allows to limit strength overestimation, often associated with the use of previous polyaxial criteria, and to easily relate uncertainties in strength estimation to uncertainty in maximum horizontal stress prediction.

Evaluation of the Lower Cretaceous Alam El Bueib Sandstone reservoirs in Shushan Basin, Egypt – Implications for tight hydrocarbon reservoir potential

This study presents the evaluation of the potential reservoir intervals in the early Cretaceous Alam El Bueib Formation of the Shushan Basin, Western Desert. Seismic 2D lines, and wireline logs (including image logs) were assessed to characterize the potential intervals. The study area is characterized by E-W to ENE-WSW striking parallel sets of steeply dipping normal faults. Based on the breakouts on image log, the regional maximum horizontal stress orientation is inferred as NE-SW. The AEB Formation, as observed on the image log, consists of massive sandstones, planar laminated siltstones, sandstone-siltstone heteroliths and laminated shales, deposited in a fluvial depositional environment. The bedding planes are WNW-ESE striking with a mean true dip of NNE (around 10°). Wireline log based quantitative petrophysical assessment identified multiple promising hydrocarbon-bearing reservoir intervals within the AEB Formation. The potential reservoir intervals are clean with shale content <10% with water saturation <50%. However, all these intervals are tight with effective porosity between 4 and 12%, dominantly ∼5%. Such tight effective porosity can be contributed by extensive silica cementation in the AEB Formation, as seen from the nearby fields in Western Desert. High porosity zones are observed to be water-bearing. The wells drilled in the north and northeastern area exhibit a cumulative net pay thickness between 70 and 150 ft, while south-southeastern region exhibits a very low cumulative net pay of 10–30 ft. Based on the breakout son image log, the regional minimum horizontal stress orientation is inferred as NW-SE, which can be preferred azimuth for placing highly deviated or horizontal wells to exploit such tight clastic reservoirs by optimizing hydraulic fracture propagation. The formation evaluation presented in this work shed critical insights into the tight hydrocarbon reservoir potential of the early Cretaceous AEB.

Evaluating the Quality and Comparative Validity of Manual Food Logging and Artificial Intelligence-Enabled Food Image Recognition in Apps for Nutrition Care.

For artificial intelligence (AI) to support nutrition care, high quality and accuracy of its features within smartphone applications (apps) are essential. This study evaluated popular apps' features, quality, behaviour change potential, and comparative validity of dietary assessment via manual logging and AI. The top 200 free and paid nutrition-related apps from Australia's Apple App and Google Play stores were screened (n = 800). Apps were assessed using MARS (quality) and ABACUS (behaviour change potential). Nutritional outputs from manual food logging and AI-enabled food-image recognition apps were compared with food records for Western, Asian, and Recommended diets. Among 18 apps, Noom scored highest on MARS (mean = 4.44) and ABACUS (21/21). From 16 manual food-logging apps, energy was overestimated for Western (mean: 1040 kJ) but underestimated for Asian (mean: -1520 kJ) diets. MyFitnessPal and Fastic had the highest accuracy (97% and 92%, respectively) out of seven AI-enabled food image recognition apps. Apps with more AI integration demonstrated better functionality, but automatic energy estimations from AI-enabled food image recognition were inaccurate. To enhance the integration of apps into nutrition care, collaborating with dietitians is essential for improving their credibility and comparative validity by expanding food databases. Moreover, training AI models are needed to improve AI-enabled food recognition, especially for mixed dishes and culturally diverse foods.

Estimation of porosity distribution from formation image logs and comparing the results with NMR log analysis: Implications for the heterogeneity analysis of carbonate reservoirs with an example from the Asmari reservoir, southwest Iran

Estimating heterogeneity in carbonate rocks is the most important parameter in identifying reservoir and non-reservoir areas. Diagenetic and sedimentary processes directly control reservoir heterogeneity. In this regard, the high hydrocarbon production rate and the reduction of the complexity of the carbonate reservoirs require the evaluation of a new architecture of the reservoir, in which the simultaneous impact of the diagenetic-sedimentary processes on the petrophysical logs is investigated. The current study studies the Oligocene-Miocene Asmari Formation Iran's giant carbonate reservoir. Based on petrographic studies, sedimentary facies, depositional environment and diagenetic processes were characterized. Formation evaluation was conducted to determine lithology, water saturation, fluid volume, and effective porosity. The estimated porosity from the evaluation of the conventional logs (full suite) was compared with the results of estimating the porosity from the NMR T2 distribution curve and the porosity histogram of the image logs. Lorenz's coefficient of heterogeneity was used to understand the heterogeneity of the reservoir. Diagenetic-sedimentary processes and petrophysical logs were used to investigate the pore type and their distribution. The results of petrographic studies, NMR T2 distribution curve, and porosity histogram show that the diagenetic-sedimentary process is the most important factor enhancing the reservoir heterogeneity. Diagenetic and sedimentary processes were traced by evaluating NMR and Image logs. Based on the results, the porosity distribution using the T2 curve and Image show a good agreement. Diagenetic processes mainly dissolution and dolomitization increased the heterogeneity of the main production zones (zones 3 and 4) of the Asmari reservoir that was confirmed using NMR and Image logs.

Development and prospect of acoustic reflection imaging logging processing and interpretation method

Acoustic reflection imaging logging technology can detect and evaluate the development of reflection anomalies, such as fractures, caves and faults, within a range of tens of meters from the wellbore, greatly expanding the application scope of well logging technology. This article reviews the development history of the technology and focuses on introducing key methods, software, and on-site applications of acoustic reflection imaging logging technology. Based on the analyses of major challenges faced by existing technologies, and in conjunction with the practical production requirements of oilfields, the further development directions of acoustic reflection imaging logging are proposed. Following the current approach that utilizes the reflection coefficients, derived from the computation of acoustic slowness and density, to perform seismic inversion constrained by well logging, the next frontier is to directly establish the forward and inverse relationships between the downhole measured reflection waves and the surface seismic reflection waves. It is essential to advance research in imaging of fractures within shale reservoirs, the assessment of hydraulic fracturing effectiveness, the study of geosteering while drilling, and the innovation in instruments of acoustic reflection imaging logging technology.

A Morphological Method for Predicting Permeability in Fractured Tight Sandstone Reservoirs Based on Electrical Imaging Logging Porosity Spectrum

Summary Permeability is a crucial parameter in formation evaluation, which reflects reservoir fluid mobility and directly influences subsequent development and production. In conventional to tight sandstone formations without fractures, numerous methods have been developed to predict permeability. However, permeability prediction accuracy based on the current method is low in fractured tight sandstone reservoirs due to the influence of heterogeneity, and little research is focused on permeability evaluation in such reservoirs. Conventional wireline and nuclear magnetic resonance (NMR) logging lose their role in fracture parameter evaluation, whereas electrical imaging logging is available for reflecting fracture information. Hence, we adopt electrical imaging logging, instead of conventional wireline and NMR logging, to predict permeability in fractured tight sandstone reservoirs. In this study, we propose a morphological method for permeability prediction using electrical imaging logging. Initially, we process the electrical imaging logging data to obtain the porosity spectra and determine the peak of the primary porosity spectrum. We then extract the mean and standard deviation of the primary porosity spectrum based on its distribution morphology. Meanwhile, we also use the normal distribution function to fit the primary porosity spectrum and accumulate the amplitudes of the original and fitted porosity spectra, respectively. When the cumulative amplitude of the fitted spectra stabilizes, the corresponding porosity indicates the boundary between primary and secondary pores. This boundary allows us to calculate the proportion of primary pores to total pores. Permeability in fractured tight sandstone formations is influenced by both primary and secondary pores, showing a strong correlation with the proportion of primary porosity. Finally, we establish a permeability prediction model based on total porosity and the proportion of matrix pores. The reliability of our established permeability evaluation model is confirmed by comparing the predicted permeabilities with core-derived results in the Triassic Chang 63 Member of the Jiyuan area in the Ordos Basin. In unfractured formations, the predicted permeability based on our raised model closely matches the results derived solely from total porosity. In fractured formations, however, the calculated permeability using our proposed model aligns more closely with the core-derived result, while predictions based on current and NMR models tend to underestimate permeability.

Implication of fast shear wave azimuth and critically stressed fractures in a coalbed methane reservoir

The orientation of the fractures and stresses within coal seams plays a critical role in gas production from coalbed methane reservoirs. In this study, we used resistivity images and sonic logs to investigate these parameters, aiming to (1) establish the relationship between fracture orientations and the polarization angles of fast shear waves and (2) detect active fractures in the coal seam. Shear waves in anisotropic formations are split into fast and slow components, with Alford’s rotation method used to determine the polarization angles of the fast shear wave. We found that the fast shear wave aligns with the direction of higher fracture intensity. Subsequently, we incorporated the poroelastic strain model to estimate the vertical ([Formula: see text]), maximum horizontal ([Formula: see text]), and minimum horizontal ([Formula: see text]) stresses in the wellbore. These stress magnitudes aided in identifying the faulting regime and were corroborated by vertical opening mode fractures. Validation of [Formula: see text] and [Formula: see text] involved comparisons with the breakout width in image logs and the closure pressure observed during hydraulic fracturing treatments. Applying Mohr’s Coulomb criteria, the stress model discerned the state of the fractures, transforming the stress magnitudes into shear and effective normal stress on each fracture plane. Our observations indicated that the identified fractures existed in a noncritically stressed condition, suggesting a lack of interconnectivity among them. These findings correspond to the absence of gas production to date, providing insights into the dynamics of fractures and their impact on production behavior.

Combined Deep-Fill and Histogram Equalization Algorithm for Full-Borehole Electrical Logging Image Restoration

Electrical borehole imaging tools cannot achieve full-borehole images due to their structure limitation. Gaps always occur between pads, and it is necessary to fill in the gaps for subsequent interpretation. In this paper, an improved model for borehole image restoration and enhancement is established by combining a “Deep-Fill” image repair algorithm based on generative adversarial networks (GANs) with histogram equalization principles. Firstly, resistivity data is converted into images, and the anomalous areas are manually repaired. Then, the manually repaired images undergo iterative training using the “Deep-Fill” model. Finally, the repaired images are further enhanced through histogram equalization principles. Results show the overall restoration quality of the model surpasses that of the original GAN-based restoration model, particularly in terms of texture coherence at junctions. This approach not only enhances the quality of repaired images but also improves the interpretability of geological features of the electrical imaging logs.

Influence of tectonic stress field on oil and gas migration in the Tahe Oilfield carbonate reservoir: Identification of areas favorable for reservoir formation

An understanding of the tectonic stress field distribution in the carbonate reservoirs of the Tahe Oilfield is essential for oil and gas migration and reservoir reconstruction. This study adopts a geological genesis perspective and integrates the unique attributes of the carbonate reservoirs in the Tahe Oilfield to simulate three-dimensional stress fields using the finite element method and Petrel software. The simulation, which takes pore pressure and boundary constraints into consideration, aligns with the findings of acoustic emission tests conducted by previous researchers and validates the model by corroborating the maximum horizontal principal stress direction with imaging logging interpretations. With subsequent utilization of the generalized Coulomb-Mohr shear failure criterion and the Griffith generalized maximum tensile stress criterion, the simulated stress enables the prediction of the total fracture intensity. To complement this analysis, we integrate seismic data and fault formation mechanisms to characterize variations in fracture intensity within distinct regions of the study area. Three key findings emerge from this investigation. First, due to the Hercynian thermal event, X-shaped conjugate faults display a disproportionately high degree of development compared to other primary fractures. Analyzing the mechanisms of formation and development of these X-shaped strike-slip faults reveals discernible differences in deformation characteristics between NW-trending and NE-trending faults, with the former exhibiting a greater propensity for fracture rupture and efficient oil-gas migration. Second, fault intersections are critical and efficient conduits for fluid accumulation and thereby contribute to reservoir formation. Lastly, exclusive of X-shaped conjugate faults, NE-trending faults exhibit the greatest propensity for oil and gas accumulation and migration. Collectively, these findings facilitate the identification of areas favorable for oil and gas migration and provide a crucial mechanical analysis that can inform the exploration and development of the Tahe Oilfield.

Characteristics and correlations of rock components, structure, and physical properties of deep clastic reservoirs in the LD-X area of Yinggehai basin, western South China Sea

Deep clastic rocks in the LD area of the western South China Sea have undergone complex and historical processes of burial, thermal evolution, and diagenesis. As important factors affecting the porosity and permeability, rock components and structures can exhibit pronounced differences with complex lithologies in the vertical direction. In this study, we used a comprehensive method to analyze the lithological characteristics through thin-section observation, scanning electron microscopy imaging, cathodoluminescence, back-scattered electron imaging (on microprobe)), X-ray diffraction patterns of clays, grain size measurement, porosity–permeability analyses, and special imaging logging. The clastic rocks in the study area are dominated by quartz, feldspar, and debris, with the main lithology being subfeldspathic sandstone. The fillings are dominated by carbonate cement, and the clays are mostly illite. The sandstone is mostly grain-supported, moderately rounded, and fine-to medium-grained with poor-medium sorting. Porosity values are mostly in the range of 5–15%, whereas permeability values are in the range of 0.05–10.00 mD. Porosity and permeability are positively correlated with the quartz and feldspar contents and grain size and negatively correlated with the rock debris and carbonate cementing materials and sorting coefficient. These different correlations indicate that the rock components are closely related to the physical properties of the reservoirs. Sandstones with better physical properties generally have higher compositional and structural maturities. On this basis, a conceptual model of the evolution of rock components, structure and physical properties in the LD area is developed. It is verified by the logging profile that rock grouping can reflect both the good and bad physical properties, while simultaneously indicating the development patterns of high-quality reservoirs in the study area.

Integrated Technique Provides Effective Water Diagnostics in Tight Sand

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3864145, “Evaluating the Hydraulic Fracture Through Acoustic Reflection Imaging and Production Logging for Water Diagnostic Beyond the Wellbore: A Case Study From Chang 8 Tight Sand in the Ordos Basin, China,” by Guangsheng Liu, Dajian Li, and Gang Zheng, PetroChina, et al. The paper has not been peer reviewed. _ The Triassic Chang 8 tight sand reservoir in the Xifeng block of the Ordos Basin features low permeability, which means that hydraulic fracturing and subsequent waterflooding were performed during its development phase. Water breakthrough was encountered after a short period of oil production. A solution of borehole acoustic reflection imaging combined with production logging was proposed in a horizontal well suffering from high water cut. The objective was to determine which stages contributed most to water production, understand the cause, and, ultimately, create a water shutoff plan. Introduction The Ordos Basin, with an area of approximately 2.5×105 km2, is in North China. The Upper Triassic Yanchang formation is subdivided into the Chang 1 to 10 members, from top to bottom. It contains significant oil reserves in siltstone and sandstone reservoirs, especially in Chang 6 through Chang 8, that have been the major oil-producing resources in recent years. In the Triassic Chang 8 tight sand reservoir, horizontal well drilling and multiple-stage hydraulic fracturing have become common practice. In the study block, the well of interest was hydraulically fractured by coiled tubing with sand-jet perforation and fracturing operations in one run with a retrievable packer in the bottomhole assembly of the coiled tubing. In the study block, when some producing wells encountered water breakthrough, traditional water diagnostics using production logging was not enough; a survey to detect hydraulic fractures beyond the wellbore was needed. Theory and Methods Borehole Acoustic Reflection Imaging. The processing workflow for acoustic reflected waves mainly consists of two parts. The first is a filtering process to suppress the borehole mode and noise in order to preserve the reflected wave. The second is to migrate the reflected wave to the true position of a reflector. The conventional migration method used for acoustic reflection imaging normally requests previous information relating to reflector dip and produces 2D images, which show the reflector shape but have hard-to-extract precise quantitative information. A trial reflector-migration method covered in the literature was introduced in 2016 that does not require input of structure dip and is of high resolution. A 3D slowness-time-coherence method was developed in 2018, also covered in the literature, that could determine the true dip, azimuth, and distance of a reflector.

Steckman Ridge: A naturally fractured underground gas storage field

This paper presents a field development case study of a gas storage field in Pennsylvania within a fractured reservoir. Integration of multiple data sets was required for the project's success. During the study, the interpretation of 3D isofrequency seismic volumes, generated through spectral decomposition, was shown to be the key step in this data integration. The interpretation of these isofrequency volumes successfully identified previously unresolved subtle structural features, which controlled the natural fracture system. The existence of these subtle structural features was subsequently confirmed with eight horizontal gas storage wells. Accurate characterization of a fracture trend requires the integration of seismic data, available well data, surface geology, drilling, and production data. This study was performed to develop the Oriskany reservoir in the Steckman Ridge underground gas storage field located in Bedford County, Pennsylvania. This field had undergone rapid depletion during its primary production phase. During the early portion of the study, the reservoir was determined to be a type 1 fractured reservoir with little to no gas storage available in the sandstone matrix. Multiple data types were acquired and integrated to detect and characterize the structural features that compose the reservoir. Isofrequency volumes, developed through spectral decomposition of 3D seismic data over the field, helped identify and map subtle shear faults that proved to be controlling the location and orientation of the dominant fracture trend in the field. Horizontal boreholes, needed to convert the field from gas production to gas storage, were planned and drilled based on this seismic interpretation. The existence of these shear faults, their location, and their orientation were confirmed by image logs acquired along the length of six horizontal gas storage boreholes. Additionally, flow tests performed to determine gas deliverability supported this interpretation.