Formation MicroScanner Images Research Articles

The spatial and geological characteristics of fault- and paleokarst-controlled carbonate-hosted reservoirs in the Tabei Uplift, Tarim Basin, China

Seismic interpretation and characterization of Middle Ordovician carbonates of the northern Tarim Basin in China reveal a series of deep-seated, sub-vertical conjugate strike-slip faults, together with sets of apparently layer-bound fractures striking parallel or orthogonal to the faults. Detailed stratigraphic analysis, well logging response interpretations (including formation microscanner images), coupled with core sample and thin section observations highlight vertical and lateral partitioning of fracturing and dissolution processes. Fracturing and dissolution development are most intense in grain-supported host rocks (grainstones, packstones) deposited in relatively shallow water conditions. Reservoir pore spaces vary systematically from north (Tahe) to south (Shunbei), which can be attributed to their proximity to a major regional angular unconformity with overlying Upper Devonian to Carboniferous sequences. Larger-scale dissolved fracture-cavity reservoirs are developed in the northern Tahe area due to the combined effects of faulting, surface karstification, and river system development close to the base Carboniferous erosion surface. Farther south, where the rocks lie farther from the paleoerosion surface, reservoir space is characterized by smaller, more structurally controlled open cavities bounded by fault slip surfaces, breccias, and open fractures. The observed interactions between paleokarstification intensity, tectonic controls, and host rock lithological layering—and their control over the observed reservoir complexity—are likely to occur in carbonate reservoirs worldwide.

Tectonic evolution of buried hills and the main controlling factors of fractures in the fault step zone of the Pearl River Mouth Basin, northern South China Sea

Buried hills are an essential offshore oil and gas exploration direction. Based on the new three-dimensional (3D) seismic data, formation micro scanner images (FMI), and zircon chronology data, the stratigraphic structure, structural characteristics, and fracture reservoir characteristics of the buried hills in the fault step zone in the Pearl River Mouth Basin in the northern South China Sea were analyzed. Then, the tectonic evolution of buried hills and the controlling factors of fracture development were discussed. From the results, the target buried hill is composed of Mesozoic volcanic rocks, and the primary reservoir types are medium-high angle structural fractures. The buried hill underwent a multi-stage tectonic evolution during the Mesozoic-Cenozoic period. Mesozoic extrusion and Cenozoic extension processes controlled the fractures in the buried hill. Shear and extensional fractures developed against Mesozoic extrusion, while shear and tensional fractures developed during Cenozoic tensional processes and magma intrusion. Tectonic movements control the development of fractures in the interior of the buried hill. Groups and types of fractures cut into each other to form network fractures, providing good reservoir space for oil and gas.

Reservoir and Fracture Characterization for Enhanced Geothermal Systems: A Case Study Using Multifractured Wells at the Utah Frontier Observatory for Research in Geothermal Energy Site

Summary For enhanced geothermal systems (EGS), multistage hydraulic fracturing along a deviated or horizontal well is a key technology used to create a high-conductivity fracture network between injection and production wells in deep, low-permeability geothermal reservoirs. The purpose of the created fracture network is to allow for the efficient transfer of fluid, heated by the geothermal reservoir, from the injection to the production well; therefore, well spacing (between injection and production wells) and hydraulic fracturing must be designed not only to promote connectivity between well pairs but also to mitigate thermal short-circuiting and thermal breakthrough. Analysis of post-fracture pressure decay (PFPD) data measured after each stage of a hydraulic fracturing treatment can be used to provide critical reservoir and fracture parameters required for well and hydraulic fracturing design optimization; this method provides a low-cost alternative and complementary approach to in-situ observation techniques, such as core-through experiments, fiber optics, or image logs in offset wells. Until now, PFPD has primarily been applied to multifractured horizontal wells (MFHWs) completed in low-permeability hydrocarbon reservoirs. The goal of this study is therefore to develop a methodology to estimate fracture and reservoir parameters using stage-by-stage PFPD data associated with EGS projects. An analytical model is proposed herein to estimate fracturing fluid efficiency, fracture length, average fracture aperture, average fracture conductivity, and reservoir permeability for different possible fracture geometries in EGS reservoirs. PFPD data collected for three hydraulic fracture stages in the injection well at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site were analyzed to demonstrate the practical application of the proposed method. The results of this study indicate that, due to the presence of natural fractures in the target (granitic) reservoir, the hydraulic fracturing treatment (using slickwater) in the openhole section resulted in low fracturing fluid efficiency and small hydraulic fractures. In contrast, hydraulic fracturing treatments conducted in the perforated casedhole wellbore resulted in higher fracturing fluid efficiency and created larger hydraulic fractures even with smaller injected volumes. The results of the PFPD analysis were confirmed using a Formation MicroScanner image log and microseismic data collected during each stage of hydraulic fracturing.

The Strike-Slip Fault Effects on the Ediacaran Carbonate Tight Reservoirs in the Central Sichuan Basin, China

The largest Precambrian gas field in China has been found in the central Sichuan Basin. It is assumed as a mound-shoal microfacies-controlled dolomite reservoir. Recently, a large strike-slip fault system has been identified in the gas field that needs further study of its effect on the Ediacaran reservoirs for highly efficient exploitation of the gas field. For this contribution, we study the matrix reservoir and fractured reservoir along the strike-slip fault damage zones by the cores, FMI (Formation MicroScanner Image) and logging interpretation data, seismic description and production data. It has shown that the matrix reservoir is tight (porosity less than 3%, permeability less than 0.5 mD) that cannot support economical production by conventional exploitation technology in the deep subsurface. On the other hand, the porosity and permeability of the Ediacaran fractured reservoirs could be increased more than one time and 1–3 orders of magnitude. Except for a few localized fracture zones, the fracture elements and fractured reservoirs show a paw-law distribution with the distance to the fault core. Furthermore, the fault effect is more favorable for the increase in the porosity and permeability of the matrix reservoir in the intraplatform than in the platform margin. The overlapping of mound-shoal microfacies, fracturing and karstification could result in large-scale “sweet spots” of the fractured reservoirs in the fault damage zone. The “sweet spot” of fractured reservoir in the fault damage zone is a new favorable exploitation target in the deep central Sichuan Basin.

Characteristics, classification and KNN-based evaluation of paleokarst carbonate reservoirs: A case study of Feixianguan Formation in northeastern Sichuan Basin, China

The Feixianguan Formation reservoirs in northeastern Sichuan are mainly a suite of carbonate platform deposits. The reservoir types are diverse with high heterogeneity and complex genetic mechanisms. Pores, vugs and fractures of different genetic mechanisms and scales are often developed in association, and it is difficult to classify reservoir types merely based on static data such as outcrop observation, and cores and logging data. In the study, the reservoirs in the Feixianguan Formation are grouped into five types by combining dynamic and static data, that is, karst breccia-residual vuggy type, solution-enhanced vuggy type, fractured-vuggy type, fractured type and matrix type (non-reservoir). Based on conventional logging data, core data and formation microscanner image (FMI) data of the Qilibei block, northeastern Sichuan Basin, the reservoirs are classified in accordance with fracture-vug matching relationship. Based on the principle of cluster analysis, K-Nearest Neighbor (KNN) classification templates are established, and the applicability of the model is verified by using the reservoir data from wells uninvolved in modeling. Following the analysis of the results of reservoir type discrimination and the production of corresponding reservoir intervals, the contributions of various reservoir types to production are evaluated and the reliability of reservoir type classification is verified. The results show that the solution-enhanced vuggy type is of high-quality sweet spot reservoir in the study area with good physical property and high gas production, followed by the fractured-vuggy type, and the fractured and karst breccia-residual vuggy types are the least promising.

Investigation of volcanic rock quantitative fracture evaluation and reservoir classification based on the logging method - an example from Nanpu Sag

Multi-stage development results in complex lithology and variable pore structure in volcanic reservoirs. Therefore, it is difficult to calculate fracture porosity and determine the volcanic reservoir type. In this study, we use the deep volcanic rock of the Nanpu No. 5 structure as an example to use a matrix porosity logging evaluation model in different lithology reservoirs. Dual Laterolog has a large detection range and is sensitive to fractures. Therefore, the relationship between igneous fracture and logging response characteristics is analysed via numerical simulation. Then, the method used for calculating fracture parameters was verified by combining formation MicroScanner image (FMI) logging technology with Dual Laterolog. For accurate reservoir classification, a fracture porosity less than 0.0005 is ineffective since the formation fluid cannot be transported. The quantitative fracture evaluation of volcanic rock reservoir was completed based on calculation model. The agreement with the actual production proved the effectiveness of the method. [Received: September 9, 2022; Accepted: December 30, 2022]

Lost circulation pattern in the vug-fractured limestone formation

Due to numerous leakage zones, such as vugs, fractures, and caves appearing in carbonate rocks, lost circulation, the main issue, restricts safe and effective drilling. The lost circulation pattern of the vug-fractured limestone formation has been extensively studied using the Mishrif formation of the H oilfield in the Middle East as the research sample. The equivalent physical models of three different types of leakage zones, including vug, natural fracture, and induced fracture, were built based on the interpretation of FMI (Formation MicroScanner Image) logging. By embedding discrete fractures into a variable permeability matrix and solving it using the finite element method (FEM), a three-dimensional fluid–solid coupling mathematical model of mud loss rate was established. The study focused on the effects of drilling fluid performance parameters on lost circulation as well as the parameters of the single leakage zone (vug, natural fracture, or induced fracture) on lost circulation. Additionally mentioned were the variable characteristics of mud loss rate and cumulative mud loss volume in various combined ways of leakage zones. The findings indicate that there are considerable differences in how various types of leakage zones affect lost circulation properties. Fractures, particularly induced fractures, can result in more severe lost circulation than those brought on by vug for the creation of a single leaking zone. Mud loss rate and cumulative mud loss volume are greatly influenced by fracture width and dissolved radius, both of which have thresholds. Due to the enhanced flow conductivity, the lost circulation is more severe the more complicated the leakage zone combination mode is. The numerical model developed in this research provides a new perspective on how to analyze the lost circulation pattern of vug-fractured limestone formations and provides theoretical direction for lost circulation control of drilling in this kind of formation.

Coupling relationship between current in-situ stress and natural fractures of continental tight sandstone oil reservoirs

We have integrated rock mechanics and acoustic experiments, full-wave array acoustic testing, formation microscanner image logging, and hydraulic-fracturing data to evaluate the coupling relationship between current in-situ stress and natural fractures. We used the data of the Yanchang Formation in the DL block of the western Ordos Basin, China, as an example. Our results find that the Yanchang Formation mainly develops high-angle fractures and vertical fractures. Furthermore, the in-situ stress state of the target sandstone strata satisfies [Formula: see text]. Nearly vertical and high-angle fractures are formed in the environment when [Formula: see text] is the maximum principal stress. Therefore, the current in-situ stress state of the target layer matches the induced fractures (longitudinal tensile-induced fractures) and natural fractures. As the buried depth increases, the difference between the horizontal maximum and minimum stresses ([Formula: see text]) has a tendency to first decrease and then increase, and its conversion depth is approximately 2000 m. Natural fractures are not developed in the distributary bay (the lowest horizontal stress area) and the thick sand area in the middle of the main river channel (the largest horizontal stress area). Natural fractures are mainly developed on the two wings of the main channel, and their horizontal stress is approximately 2–4 MPa lower than the central part of the main channel. We determined a correlation between fractures and sedimentary facies, and we have an important reference value for improving the drilling success rate of tight oil reservoirs. Furthermore, our study provides insights into the prediction of fractures and sweet spots for further exploration and hydraulic fracturing activities in the studied area and elsewhere in continental tight sandstone reservoirs.

Simulation-based three-dimensional model of wellbore stability in fractured formation using discrete element method based on formation microscanner image: A case study of Tarim Basin, China

Wellbore instability in fractured formation is a major challenge in drilling engineering, especially in the oil and gas energy sector. This study aims to analyze wellbore stability in fractured formation using discrete element method. A novel fractures modeling method by using formation microscanner images (FMI) and image processing was proposed. Three wellbore models with different fracture structures, and a no fracture model are developed to simulate the wellbore drilled in X well, Tarim Basin, China. Different drilling fluid densities are applied to the four models. Failures and deformation of wellbore models are investigated. Large amounts of displacement and yielded zones around the wellbore were observed in the high and low dip intersecting fractures models. And fluid density has few effects on the wellbore stability. High dip fracture is considered a major factor in wellbore instability. The high drilling fluid density performed better in the low dip fracture model, and the low drilling fluid density performed better in the vertical fracture model and intact model. The proposed modeling method and findings have important implications for understanding the wellbore instability in fractured formation.

Integrated characterization of ultradeep reef-shoal reservoir architecture: A case study of the Upper Permian Changxing Formation in the giant Yuanba gas field, Sichuan Basin, China

The Yuanba giant gas field in the Sichuan Basin produces from Upper Permian Changxing heterogeneous reef-shoal reservoirs. It is an ultradeep tight gas reservoir with burial depth of 7000 m. This paper proposes an integrated methodology incorporating the reservoir geology description, petrophysics characterization, seismic response analysis, forward seismic modeling, pseudo-acoustic inversion, and reservoir architecture imaging to identify the geologically complex reef-shoal reservoirs and predict the distribution of the producible reservoirs. The facies of reef cap, reef core, reef base and shoal are first identified based on observations and interpretations of cores, thin sections, mud logging, wireline logs, and formation microscanner images (FMIs). High-energy shoals, reef cores, and reef caps are the most favorable reservoir microfacies. Seismic responses of reef-shoal reservoirs are then investigated through forward modeling and well-seismic calibration. Four reef belts are identified based on seismic reflections and edge detection by seismic paleogeomorphologic features. Reservoir distribution and quantitative properties are predicted using the facies-controlled postattack seismic inversion technique through the correlation between reservoir properties and seismic attributes, which is aided by pseudo-gamma acoustic inversion to exclude the shale-bearing non-reservoir and pseudo-neutron acoustic inversion based on its good relationship with porosity. The reef reservoir thicknesses range from 10 m to 130 m, and the thickest reservoir is located in the northwestern Yuanba gas field. Finally, 3-D visualization is used to characterize the spatial variation of the interior architecture, connectivity, and distribution of a good reservoir in the reef system. The accuracy rate of prediction for reservoirs and non-reservoirs reaches 88% using this method. The technique has also been successfully used for the deployment of development wells and well trajectory optimization, and the rate of encountering the predicted reservoirs is 100%. This study provides a practical approach to identify and predict the tight carbonate gas reservoir with similar petrophysical responses of density and acoustic to non-reservoirs in the complex carbonate system.

A new monitoring method for overlying strata failure height in Neogene laterite caused by underground coal mining

Determination of the overlying strata failure height, that is, water flowing fractured zone height (WFFZH), is critical to underwater coal mining, especially in the fragile geo-environment areas. Due to the property discrepancy of rock and soil, WFFZH penetrating the clay layer in the Jurassic coalfield cannot be accurately determined by conventional measurement method, a new formation micro-scanner image (FMI) method was presented and verified in the paper. Taking the N1208 coalface in the Shennan mining area, Shaanxi, China, as a case study, FMI based field test for monitoring WFFZH was carried out firstly. The scanning results show that subtle changes of drilling sidewall cracks could be presented intuitively in FMI scanning image, and the WFFZH was be determined as 145.15 m. Secondly, the whole evolutionary process of WFFZH is simulated using UDEC, whose maximum height of WFFZ is calculated as 147.0 m. Comparison results between on-site measurement and numerical simulation suggest that FMI technology is applicable to monitor the WFFZH in laterite layer. Thirdly, in order to illustrate the discrepancies in WFFZH developed in laterite and bedrock, a comparative numerical simulation tests results show that laterite layer has an inhibitory effect on WFFZH.

Hydrothermal dolomite reservoirs in a fault system and the factors controlling reservoir formation-A case study of Lower Paleozoic carbonate reservoirs in the Gucheng area, Tarim Basin

The widespread hydrothermal activity in the Lower Paleozoic carbonate reservoirs of the Tarim Basin has received much attention. The discovery of hydrothermal dolomite reservoirs indicates that hydrothermal alteration may have a positive effect on reservoir development. However, the factors controlling hydrothermal dolomite reservoirs and their pore development characteristics are difficult to recognize and interpret. Based on the lithology, petrology, pore fabrics and geochemical characteristics of the Lower Paleozoic carbonate reservoirs in the Gucheng area, this research discloses that the origin of the carbonate reservoirs is related to alteration by hydrothermal brine. Further, hydrothermal dolomite reservoirs are strongly heterogeneous in different fault zone structures. This research divides the fault structures into fault cores (type 1) and damage zones (types 2 and 3). Type 1 is characterized by many breccias cemented by saddle dolomite, locally developed vugs or fractures in the cores, low density (1.7–2.8 g/cm3) and resistance (22.4–1075 Ω) in the log response, and shows abundant black-spotted vugs and sinusoidal fractures in formation microscanner images (FMI). Due to poor connectivity and high heterogeneity (permeability: 3.24 to 0.01 mD, average 0.59 mD; porosity: 5.1 to 0.7%, average 1.8%), type 1 hydrothermal dolomite reservoirs show both positive and negative hydrothermal fluid contributions. In the damage zones, especially in the areas near fault cores, type 2 is rich in fracture-pore systems in both the cores and FMI and is characterized by serrated fluctuations in acoustic waves and densities (2.4–2.8 g/cm3). Type2 performs well in terms of physical properties (permeability: 8.06 to 0.011 mD, average 0.837 mD; porosity: 6.6 to 0.65%, average 2.5%), indicating potentially favorable areas for the development of hydrothermal dolomite reservoirs. At the distal end of a damage zone or in poorly developed areas, type 3 features filling by hydrothermal products or higher densification (permeability: 0.77 to 0.0003 mD, average 0.125 mD; porosity: 1.6 to 0.2%, average 0.2%). The well logging response of type3, which has a density of around 2.8 g/cm3 and flat acoustic wave curves, is similar to that of the host rock. The differences in the development of hydrothermal dolomite reservoirs among diverse fault zones suggest that the damage zone (type 2) may be a potential area for hydrothermal dolomite reservoirs in the fault system. This study illustrates a model in which the hydrothermal fluid dissolves host rock in the proximal area and precipitates it at the distal end of the damage zone. The hydrothermal dolomite reservoir characteristics of different fault zones are also further interpreted and described. Therefore, different locations within a fault zone need to be considered and distinguished in studies of the factors controlling hydrothermal dolomite reservoirs in fault systems. This view may provide new ideas regarding whether hydrothermal activity in the Tarim Basin plays a positive role in the formation of reservoirs and offers new suggestions for the exploration of hydrothermal dolomite reservoirs in fault systems.

Developmental characteristics and distribution law of fractures in a tight sandstone reservoir in a low‐amplitude tectonic zone, eastern Ordos Basin, China

In recent years, a large number of vertical and horizontal sliding fractures were found in the Upper Palaeozoic sandstones in the eastern margin of the Ordos Basin, China, However, the effect of fractures on the distribution of tight sandstone gas is still unclear. Therefore, in this paper, a large number of cores, thin sections, petrophysical property test results, conventional and FMI (Formation MicroScanner Image) image logs, and gas‐testing results were used to study the developmental characteristics of fractures and the gas control effects in a tight sandstone reservoir, in the eastern margin of the Ordos Basin. It was found that the average linear density of the core fractures is generally less than 2 m−1, and the microfractures are characterized as ruptures of quartz particles. The underlying Taiyuan and Benxi formations have the highest fracture development degrees, and the fracture index (FI) values are 0.68 and 0.72, respectively. However, the fracture development degrees in the overlying Shanxi to Shiqianfeng formations are significantly lower, and the FI values are generally less than 0.63. There is a good positive correlation between the fracture development degree and the contents of quartz mineral or brittle minerals (quartz + feldspar). On the whole, the fractures in the uplift and slope parts of the low‐amplitude structure areas are more developed, while in the depression zones, the fractures are generally less developed. The fractures in the Zijinshan Uplift area are extremely well developed; thus, the preservation conditions of the reservoir are poor. In this case, the fractures are unfavourable for the accumulation of natural gas. For the gentle tectonic zones, the over‐developed fractures in the Benxi and Taiyuan formations are unfavourable for the preservation of natural gas. However, the moderately developed fractures in the overlying Shanxi to Shiqianfeng formations are beneficial to the enrichment of natural gas. Finally, we compared the relationship between fracture index (FI) and open‐flow productivity of the gas wells, and it was found that FI values of commercial gas wells (Types I, II, and III gas wells) are generally greater than 0.55, while the FI values of Type IV low‐yield gas wells are generally less than 0.55.

Grading evaluation and prediction of fracture-cavity reservoirs in Cambrian Longwangmiao Formation of Moxi area, Sichuan Basin, SW China

Abstract By using core, thin section, well logging, seismic, well testing and other data, the reservoir grading evaluation parameters were selected, the classification criterion considering multiple factors for carbonate reservoirs in this area were established, and the main factors affecting the development of high quality reservoir were determined. By employing Formation MicroScanner Image (FMI) logging fracture-cavity recognition technology and reservoir seismic waveform classification technology, the spatial distribution of reservoirs of all grades were predicted. On the basis of identifying four types of reservoir space developed in the study area by mercury injection experiment, a classification criterion was established using four reservoir grading evaluation parameters, median throat radius, effective porosity and effective permeability of fracture-cavity development zone, relationship between fracture and dissolution pore development and assemblage, and the reservoirs in the study area were classified into grade I high quality reservoir of fracture and cavity type, grade II average reservoir of fracture and porosity type, grade III poor reservoir of intergranular pore type. Based on the three main factors controlling the development of high quality reservoir, structural location, sedimentary facies and epigenesis, the distribution of the 3 grades reservoirs in each well area and formation were predicted using geophysical response and percolation characteristics. Follow-up drilling has confirmed that the classification evaluation standard and prediction methods established are effective.

Formation MicroScanner Providing Better Answers for Carbonate Secondary Porosity in Alamein Dolomite Formation, NW Desert, Egypt

The use of borehole imaging tools has become widespread in recent years with more specialized studies of reservoir properties, particularly in highly-porous and fractured carbonate systems. In this study, the Formation MicroScanner (FMS) borehole imaging tool and conventional well log data have been used to study the secondary porosity of the dolomitic Alamein Formation in the Alamein Field, north Western Desert, Egypt. Based on well log analyses of the formation from Tourmaline-1X and N.Alamein-6X wells, we show that secondary porosity occurs across the formation, and is filled mostly with hydrocarbon. We also show that the formation has good average effective porosity and hydrocarbon saturation. FMS images of the Tourmaline-1X well confirms that the formation is intermittently vuggy with solution-filled channels from the top to its base. The vug pores are observed to be well-connected, which supports good effective porosity values interpreted from petrophysical data. An additional set of core photographs of the Alamein Formation from N.Alamein-5X well confirms the presence of secondary pores, which are filled by hydrocarbon, and exhibit intense fluorescence under UV light. Our results show that the abundance of secondary porosity in Alamein Formation would play a key role in evaluating its reservoir quality and reservoir performance.

Integrated detection of fractures and caves in carbonate fractured-vuggy reservoirs based on seismic data and well data

Aiming at the prediction of carbonate fractured-vuggy reservoirs, we put forward an integrated approach based on seismic and well data. We divide a carbonate fracture-cave system into four scales for study: micro-scale fracture, meso-scale fracture, macro-scale fracture and cave. Firstly, we analyze anisotropic attributes of prestack azimuth gathers based on multi-scale rock physics forward modeling. We select the frequency attenuation gradient attribute to calculate azimuth anisotropy intensity, and we constrain the result with Formation MicroScanner image data and trial production data to predict the distribution of both micro-scale and meso-scale fracture sets. Then, poststack seismic attributes, variance, curvature and ant algorithms are used to predict the distribution of macro-scale fractures. We also constrain the results with trial production data for accuracy. Next, the distribution of caves is predicted by the amplitude corresponding to the instantaneous peak frequency of the seismic imaging data. Finally, the meso-scale fracture sets, macro-scale fractures and caves are combined to obtain an integrated result. This integrated approach is applied to a real field in Tarim Basin in western China for the prediction of fracture-cave reservoirs. The results indicate that this approach can well explain the spatial distribution of carbonate reservoirs. It can solve the problem of non-uniqueness and improve fracture prediction accuracy.

Quantitative prediction of fracture distribution using geomechanical method within Kuqa Depression, Tarim Basin, NW China

Understanding and predicting the development and distribution of tectonic fractures in the super-deep tight sandstone reservoir are important for both gas exploration and exploitation activities in Kuqa Depression. We analyzed the characteristics of regional structural evolution and paleotectonic stress field setting. A reasonable geological model of the research area was built based on an interpretation of the geological structure, a test for rock mechanics, and experiment on acoustic emission. Thereafter, a three-dimensional paleotectonic stress field during the Late Himalayan movement was simulated by the finite element method. Composite rock failure criterion and geomechanical models between fracture density, aperture, strike and strain energy density were used to determine the quantitative development of fractures and predict zones that are prone to fracture development. Areas with well-developed tectonic fractures are mainly controlled by the tectonic stress field and elastic strain energy density, typically located in the fold limbs, fault zones and locations of changes in the orientation of fault. In turn, factors of faults, the lithology, depth and curvature control the development and distribution of tectonic fractures in the tight sandstone. The overall simulated results match well with core observation and FMI (Formation MicroScanner Image) results both in the whole geometry and fracture distribution. This evolutionary model of the structures present to us is a distinct and intuitive top-popup fold with low amplitude and relatively low-density fractures in the top, has only experienced pre-folding stage and strong folding stage, and has not yet been developed to vertical uplift stage.

Reservoir geomechanical modeling: In-situ stress, pore pressure, and mud design

This paper, demonstrated a scientific approach to prepare a geomechanical model for Bangestan reservoir in an oil well in the south-west of Iran. Bangestan is one of the most important oil reservoirs in the Middle-East that its geomechanical characters are not perfectly known. Moreover, unexpected problems such as casing collapse, production drop and land subsidence occurred in this reservoir that made it necessary to conduct a comprehensive geomechanical model. According to borehole failure observations from a formation micro scanner (FMS) image log, the direction of minimum and maximum horizontal in-situ stresses (Sh and SH) were N35E and N55W, respectively. Also, using poro-elastic formulations, in-situ stress regime was found to be strike-slip (i.e. SH>Sv>Sh). Besides, the optimum mud weight for safe drilling at borehole breakout based on Mohr-Coulomb and Mogi-Coulomb criteria were found 85.12 and 80.42 pcf, respectively, while 79 pcf had been applied in practice. Finally, the precision of the geomechanical model was evaluated using natural fracture observations in the FMS image logs. The FMS logs revealed a total of 510 natural fractures in five clusters. In case of all fracture intervals, petrophysical properties and in-situ stresses decreased and therefore, the model was adequately sensitive to the fractures.

Paleokarst system based on FMI facies analysis: a case study in the Yingshan Formation at the Tazhong uplift in the Tarim Basin, Northwest China

FMI (Formation Micro-Scanner image) is a widely used technique to analyze reservoir properties with the advantages of being high resolution and providing a visible and quantifiable image. In this study, eleven FMI facies are classified based on integrating borehole images, cores, thin sections, and well logs. The facies include such reservoirs as caves and tectonic fractures, sedimentary interbeds, such as high-resistivity facies, and two facies of fractures and holes. In addition to the description of karst systems in the borehole images, anomalies in the GR (gamma ray) well log curve may complement the results from the FMI images. The GR curve shows that the composite facies of fractures and holes could be an effective reservoir instead of caves with high GR values because the holes filled with oil and gas are connected by fractures. Two suites of karst systems formed in the SQ4, while small scale caves and holes formed in the SQ3 because of their lithological and structural locations. The results of this study demonstrate that unconformities and tectonic geomorphology control the differences between the paleokarst systems.

Simulation of paleotectonic stress fields within Paleogene shale reservoirs and prediction of favorable zones for fracture development within the Zhanhua Depression, Bohai Bay Basin, east China

Abstract Objective Tectonic fractures are the most important reservoir spaces within shale reservoirs and can significantly improve the permeability of a reservoir, the development and distribution of these fractures are controlled by paleotectonic stress fields. An important hydrocarbon reservoir is hosted by a Paleogene shale unit within the lower section of the third member of the Shahejie Formation (Es3) within the Zhanhua Depression of the Bohai Bay Basin, east China. Industrial-level oil and gas production has been obtained from over 30 wells with the highest single well production of 93 t/d, indicating the large oil and gas potential of these reservoirs in the Zhanhua Depression. Methods The data obtained from cores, logs, and drilling in the Zhanhua Depression can be used to identify the processes involved in the development of such tectonic fractures. In this study, these data were combined with additional acoustic emission and rock mechanics data to identify the effects of faulting and lithological variations on the development of fractures using a finite element method (FEM) stress analysis approach that simulated paleotectonic stress fields during the late Dongying stage, the period of time when the majority of the fractures developed. Estimations of rock failure criteria and comprehensive indexing of rupture rates for tectonic fractures were undertaken to determine the quantitative development of fractures and to predict favorable zones for fracture development. Results Tectonic fractures within the shale reservoir in the lower part of the Es3 unit include both tensional and shear fractures, these fractures are generally unfilled or half-filled. The NE–SW strike of these fractures is consistent with the orientation of the present stress field, meaning that these fractures were high-priority targets during initial well targeting. Tectonic fractures can be identified during logging by increased resistivity (R2.5), increased acoustic time difference (AC) values combined with cycle skip of the peaks, and highly variable but generally elevated gamma ray (GR) values. Fractures can also be directly identified, and fracture parameters can be determined using Formation MicroScanner Image (FMI). The magnitude of the maximum principal stress during the major period of fracture development within the Zhanhua Depression was 53.2 MPa, and the paleotectonic stress field was controlled by the location of fault zones. In contrast, areas without fractures have stress fields that were influenced by lithological variations, leading to the development of high stress fields in areas with rocks containing high concentrations of carbonate. Conclusion Fracture development is controlled by tectonic stress fields and fractured areas are generally located between fault zones, at the intersection of faults, in areas when fault orientations change, and at high stress areas near fault tips. The present results regarding predictions of the locations of fractured areas are consistent with the location of producing oil and gas wells.