Fracture Orientation Research Articles

Fracture Propagation Laws and Influencing Factors in Coal Reservoirs of the Baode Block, Ordos Basin

The expansion of hydraulic fractures in coalbed methane (CBM) reservoirs is key to effective stimulation, making it essential to understand fracture propagation and its influencing factors for efficient resource development. Using petrological characteristics, logging data, microseismic monitoring, and fracturing reports from the Baode Block on the eastern Ordos Basin, this study systematically investigates the geological and engineering factors influencing hydraulic fracture propagation. The real-time monitoring of fracture propagation in 12 fractured wells was conducted using microseismic monitoring techniques. The results indicated that the fracture orientations in the study area ranged from NE30° to NE60°, with fracture lengths varying between 136 and 226 m and fracture heights ranging from 8.5 to 25.3 m. Additionally, the fracturing curves in the study area can be classified into four types: stable, descending, fluctuating, and falling. Among these, the stable and descending types exhibit the most effective fracture propagation and are more likely to generate longer fractures. In undeformed–cataclastic coals and bright and semi-bright coals, long fractures are likely to form. When the Geological Strength Index (GSI) of the coal rock ranges between 60 and 70, fracture lengths generally exceed 200 m. When the coal macrolithotype index (Sm) is below 2, fracture lengths typically exceed 200 m. When the difference between the maximum and minimum horizontal principal stresses exceeds 5 MPa, fractures with length >180 m are formed, while fracture heights generally remain below 15 m. From an engineering perspective, for the study area, hydraulic fracturing measures with a preflush ratio of 20–30%, an average sand ratio of 13–15%, and a construction pressure between 15 MPa and 25 MPa are most favorable for coalbed methane production.

A time-lapse multicomponent (9C 4D) seismic study at Vacuum Field, New Mexico, USA

In November and December 1995, the Reservoir Characterization Project (RCP) at the Colorado School of Mines acquired time-lapse multicomponent 3D surveys over the Central Vacuum Unit of Vacuum Field in Lea County, New Mexico. Two surveys were acquired — one before and one after the injection of 50 MMscf CO2 through a single wellbore into the San Andres Reservoir. The project determined that repeated multicomponent seismic surveys at the earth's surface can detect changes in bulk rock properties due to variations in reservoir pressures and fluid properties. Interpretation of the dynamic seismic response due to reservoir production processes over time provides an image of the relative permeability structure of the reservoir. Time-lapse multicomponent data were acquired using three-component geophones and vertically and horizontally actuated vibrator sources at the surface. A data processing flow was developed for time-lapse multicomponent 3D surveys. It uses surface-consistent processing algorithms and the source and receiver redundancy between initial and repeat surveys to derive surface-consistent corrections. Differences in S-wave polarization are measured between the initial and repeat surveys. S-wave data show sensitivity (through birefringence) to anisotropy caused by the orientation of fractures and low-aspect-ratio pore structure in a nonuniform stress field. The direction of fast S-wave polarization can be related to the direction of maximum horizontal stress and preferential permeability. Pore-pressure variations alter the effective stress. This varies the direction and intensity of open fractures and low-aspect-ratio pore structure within the current permeability structure of the reservoir, causing detectable changes in S-wave anisotropy. Anomalies in S-wave anisotropy, interpreted from time-lapse multicomponent 3D data, in conjunction with reservoir production data, are consistent with the fluid composition and pore-pressure changes associated with the CO2 injection program and reservoir processes in the survey area. Applications include monitoring hydrocarbon enhanced oil recovery; carbon capture, utilization, and storage; hydraulic stimulation; induced seismicity; and geothermal investigations.

Impact of natural fractures on hydraulic fracture propagation in Denver-Julesburg Basin: Insights from a decade of research

The Denver-Julesburg (DJ) Basin is a key region for unconventional oil and gas extraction, particularly from the Niobrara and Codell formations. This study synthesizes findings from a decade of research conducted in three different geographic areas of the basin as part of the industry consortium Reservoir Characterization Project at Colorado School of Mines. The research explores how natural fractures affect hydraulic fracture propagation, leveraging geophysical data sets including 3D seismic imaging, image logs, microseismic monitoring, and crosswell distributed strain sensing. Key observations reveal significant variations in hydraulic fracture orientations and propagation speeds between the Niobrara and Codell formations, which are the main targets for horizontal drilling and stimulation. High natural fracture densities and orientations notably influence the propagation of hydraulic fractures in the Niobrara Formation, deviating them from the regional maximum horizontal stress (SHmax) directions, while hydraulic fractures in Codell consistently align with SHmax where lower natural fracture densities are observed. The study also highlights the critical role of stress anisotropy and zipper fracturing sequences in dictating hydraulic fracture behavior. Additionally, a marked negative correlation between natural fracture density and hydraulic fracture propagation speed underlines the fracture network complexity added by natural fractures. These findings advocate for a comprehensive natural fracture characterization and tailored fracturing strategies to optimize well placement and completions. The implications for DJ Basin development from this study are profound, suggesting that understanding local geomechanics and fracture networks can significantly enhance hydrocarbon recovery. Future work should focus on more precise assessments of hydraulic fracture interactions with natural fracture systems to refine operational strategies further.

A transient source-function-based embedded discrete fracture model for simulation of multiscale-fractured reservoir: Application in coalbed methane extraction

The classic embedded discrete fracture model (EDFM) may cause certain errors when simulating the transient flow process within the multi-scale fractured system. In this study, the transient transmissibility was derived by using the point (matrix-fracture) and line (fracture-fracture) source functions. The transient source-function-based EDFM (tSEDFM) is established via this method. Then, based on the dual criteria that dNNC is less than a certain distance and its projection point is within the corresponding fracture domain, a 3D fracture meshing method for arbitrary fracture geometry and orientation is established. The finite volume method is used to discrete the fluid flow equations for matrix and fracture systems, considering the multi-deformation-induced permeability evolution. Consequently, the numerical simulation framework of FVM-tSEDFM is proposed to investigate the transient mass transfer characteristics. Compared with the current pEDFM, the pressure drop near fractures of the proposed model is higher and the gap narrows as pressure wave further spreads. Compared with AEDFM, the Tmf of tSEDFM is almost the same, but AEDFM's Tff is substantially higher in the initial stage and the attenuation rate is slower, resulting in an error of nearly 15% at the hydraulic fracture location. As fracture density increases, more transient flow makes AEDFM- and EDFM-calculated BHP values deviate from tSEDFM. History matching using the tSEDFM with only 10000 meshes shows better results where the mismatching rate is larger than 90%. Simulation of CBM extraction indicate that sharp pressure decline occurs near the fractures, resulting in gas desorption enhancement and rapid productivity increment. The tSEDFM demonstrates good practicality in calculating the production and long-term permeability evolution. Results also show that the tSEDFM can correct the underestimation of mass exchange in the early stage and overestimation since the pseudo-steady stage, and can be better applied to the numerical simulation of multi-scale fractured reservoirs. As the dominant factor for gas extraction, sensitivity analyses of fracture properties are also documented.

A novel meshless method for numerical simulation of fractured-vuggy reservoirs

This paper proposes a novel meshless numerical simulation method for fractured-vuggy reservoirs. Initially, model discretization involves extracting fracture and vug feature nodes along the contours of the reservoir bodies and in alignment with fracture orientations, tailored to the characteristics of the fractured-vuggy oil deposit. Subsequently, a connection element model is established within the influence domain. Based on the seepage equations of the connection system, a computational method for the parameters of the connection elements (connection transmissibility and connection volume) is defined. In addition, a sequential method is employed to solve for the pressure and saturation, achieving rapid prediction of the reservoir's production dynamics. On this basis, an automatic history matching algorithm is utilized for real-time fitting of oil–water dynamic indicators, inverting the characteristic parameters of the connection element model, and quantitatively characterizing the injection–production connection elements. The research findings indicate that the method is capable of rapidly fitting and predicting the dynamics of oil reservoir production. Furthermore, conceptual model examples have substantiated that it achieves comparable computational efficiency and superior computational accuracy when compared to the traditional finite difference (volume) method under the same nodal conditions. Additionally, the node arrangement for fractures and vugs is comparatively flexible, and it can ensure the integrity of the flow paths with a limited number of nodes to enhance predictive accuracy. Therefore, this method can effectively meet the rapid prediction requirements for fractured-vuggy reservoirs and also provides a novel meshless computational approach for the numerical simulation of such reservoirs.

Application of Microseismic Monitoring in Fracturing Process Evaluation

Abstract Fracture-mesh control technologies, such as modified liquid system (controlled fracture technology), pulse fracturing reform and directional perforation technology, have been adopted in the large-scale fracturing process of well Qaiping 1 in Qaidam Basin. However, whether the technology has achieved the predetermined goal needs to be verified. In order to fully grasp the fracture morphology in each stage of fracturing construction, the underground microseismic fracture monitoring technology is used to reveal the fracture length, height, width, orientation and spatial distribution characteristics. Based on the analysis of monitoring results, the following conclusions are obtained. (1) The collection of microseismic event data plays a key role in interpreting the properties of fractures, so as to more accurately understand and predict the formation and development of fractures. (2) Real-time microseismic monitoring reveals the application value of a variety of special processes in the formation reconstruction effect, and the transformation of liquid system (controlled fracture process), pulse fracturing and directional perforating process have significant effects on fracture morphology.

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.

Building the fracture network model for the Okuaizu geothermal field based on microseismic data analysis

Understanding flow behavior in a geothermal reservoir is important for managing sustainable geothermal energy extraction. Fluid flow in geothermal reservoirs generally occurs in complex existing fracture systems in which the reservoirs are situated in highly fractured rocks. To simulate a discrete fracture model, the location and orientation of the fracture were computed using statistical processes and observational data. In many cases, estimating the location and orientation of fractures from 1D borehole logging data is challenging. In this study, we used microseismic data to build the fracture network systems and extract the detailed positions and dimensions of the fractures. We used the microseismic data recorded at the Okuaizu Geothermal Field, Fukushima Prefecture, Japan, from 2019 to 2021. First, we located the hypocenters, removing the effect of uncertainty in the velocity structure of the geothermal fluids. We relocated and clustered the seismic events based on waveform similarity. We analyzed each cluster to define the fracture orientation using principal component analysis (PCA) and focal mechanism (FM) analysis. We used the P polarity with the S/P ratio as a constraint for a better fault-plane solution. With PCA, we can extract the fracture dimension of each cluster. Our cluster analysis showed that the clusters were not always planar fractures, and we interpreted them as fracture zones. Based on the consistency between PCA and FM, each cluster/fracture zone was classified into three conceptual models to characterize the fracture network system in this field. This model showed variations in the orientation of small fractures within the fracture zone. We characterized the spatial variation in fracture distribution and orientations in the reservoir and demonstrated the fracture network system of this field. The fracture zone near the injection well has a N–S strike, and the dip is above 80°; however, the fracture zone in the northeastern part of the injection well has a NW–SE strike with a dip between 60° and 80°. The fracture network system estimated in this study is crucial for robust reservoir modeling because our model is more realistic, observation-orientated, and includes local anomalies of reservoir properties.Graphical

Experimental study on directional fracturing by slotted hydraulic blasting in underground drilling

This paper proposes a method for creating a three-dimensional (above-ground and underground) fracture network in deep coalbed methane (CBM) reservoirs, which is the directional fracturing by slotted hydraulic blasting in underground drilling. First, theoretical analysis was conducted to explain the mechanism by which the slotted borehole enables the separation and incidence of explosive shock wave at the slot tip, resulting in the superposition of two sub-stress waves to cause directional fracture and damage to the rock. Then, LS-DYNA was used to simulate the process of directional fracturing by slotted hydraulic blasting to verify the theoretical mechanism. Finally, similar simulation experiments were performed on traditional blasting and slotted hydraulic blasting to confirm the directional fracturing effect of the proposed method. The results indicate that the slotted hydraulic blasting method can predominate the fracture orientation under formation stress, creating extensive directional fractures in rocks in the slot direction. This study is supplemental to the efforts on directional fracturing of rocks and provides a new approach for efficient exploitation of CBM.

Solute transport characteristics of columnar volumetric contraction networks with mega column structure and aperture variability

Numerical simulations explore for the first time the role of mega columns and aperture variability on particle transport through mature volumetric contraction networks as informed by a unique synthesis of network propagation and maturity. Columnar fracture patterns are generated by updating a series of Voronoi centers to the midpoint of a generated polygon over many iterations, creating 250 network realizations. A DFN simulator solves for fluid flow and tracks conservative particle trajectories within each network. Dominant fracture attributes impacting fluid flow and solute transport in volumetric contraction networks are fracture orientation, density, and aperture/transmissivity. Ensemble plume snapshots generated by networks with equal fracture transmissivity define a baseline-level of dispersion that is solely attributed to network structure and connectivity. Longitudinal and transverse dispersion increase and the center of plume mass becomes delayed relative to the baseline case when fracture transmissivity is varied according to a lognormal distribution. The incorporation of highly-transmissive, large-aperture mega column fractures leads to plume snapshots with a more pronounced leading edge and an order of magnitude faster average breakthrough times. The breakthrough curves contain three peaks reflecting contrasting transport pathways in which particles are: (i) initially placed in mega column fractures and remain in these features until exiting the model domain, (ii) initially placed into small column fractures, incur additional time to migrate and enter a mega column fracture, and remain within those mega columns, and (iii) initially placed in small column fractures and remain in these fractures. Incorporating variability in fracture transmissivity for both small column and mega column fractures disrupts the binary distinction between small column and mega column fracture velocities and leads to dispersed breakthroughs over long time scales with a single peak. These results demonstrate that preferential flow paths emerge in volumetric contraction networks due to contracts in fracture transmissivity, not fracture connectivity as observed in tectonic networks.

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.

High-resolution analysis of 3D fracture networks from Digital Outcrop Models, correlation to plate-tectonic events and calibration of subsurface models (Jurassic, Arabian Plate)

The performance of different reservoirs, both hydrocarbon and gas storage, is significantly influenced by the presence of natural fracture networks mainly originated in response to tectonic deformation. However, adequate characterization of fracture networks in the subsurface is often difficult since most of the used techniques are either spatially sparse (well and log data) or have limited resolution (seismic and well tests). In this study, we use UAV-based digital photogrammetry to reconstruct a 3D Digital Outcrop Model and characterize natural fracture sets of the late Jurassic Hanifa Formation (Tuwaiq Escarpment, Saudi Arabia). We analyzed the exposed fracture patterns in terms of fracture distribution, intensity, and lateral variability. The fracture dataset was collected using manual sampling approaches since the automatic sampling techniques are highly influenced by outcrop morphology thus not yet reliable to quantify and interpret fracture networks along reservoir outcrop analogues. The well-exposed late Jurassic outcrops in Wadi Birk, southern central Saudi Arabia, are considered analogous in depositional facies to subsurface reservoirs in the region. The observed fracture patterns are congruent with patterns reported from same-age formations in other parts of the Arabian Plate and hence can be related to plate-wide tectonic events that impacted Arabia during the Late Cretaceous (Alpine I) and the late Tertiary Period (Alpine II). This association provides support for using outcrop-based fracture studies as analogue scenarios for the orientation, distribution and intensity of fractures in subsurface reservoirs. The applied methodology for fracture network characterization have potential implications for hydrocarbon development, gas storage (H2) and Carbon Capture Utilization and Storage (CCUS).

Role of 3D CT with Humeral Subtraction in Assessing Anteromedial Facet Coronoid Fractures

BackgroundThe anteromedial facet (AMF) of the coronoid is a key structure in resisting varus posteromedial rotatory instability (PMRI) of the elbow. However, not all isolated coronoid fractures involve the AMF and not all fractures involving the AMF are the result of a PMRI mechanism. There is debate regarding the management of isolated coronoid fractures. A reliable method of differentiating this heterogeneous group of isolated coronoid fractures is essential to develop an appropriate management algorithm. The aim of this study was to evaluate the role of additional humeral subtraction 3D images in the detailed assessment of the known radiographic features of AMF fractures with PMRI mechanism. MethodsThree upper extremity fellowship-trained orthopedic surgeons evaluated 32 consecutive CT scans in patients with isolated coronoid fractures, on two occasions separated by at least 5 months. On each occasion, CT scan images were evaluated for fracture morphology and orientation in two rounds. In the first round, the evaluation was made based on all 2D and 3D reconstruction images of the entire elbow; in the second round, the surgeons had access to images from the first round plus 3D reconstruction with humeral subtraction. Statistical analysis to assess agreement amongst the surgeons was performed using the kappa multi-rater analysis. Intraobserver agreement was evaluated using Pearson’s correlation coefficient. ResultsThe addition of the humeral subtraction view significantly improved the interobserver agreement for fracture morphology from 0.28 (95% CI 0.07-0.49) to 0.66 (95% CI 0.46-0.87), p< 0.001; and for orientation from 0.31 (95% CI 0.09-0.52) to 0.54 (95% CI 0.31-0.77), p<0.001. Similarly, the intraobserver Pearson correlation improved from 0.28-0.38 to 0.48-0.76 for fracture morphology, and from 0.36-0.77 to 0.51-0.69 for fracture orientation. Conclusion3D CT reconstruction with humeral subtraction improved surgeons’ ability to characterize radiographic features of AMF coronoid fractures. Future studies are required to determine whether better characterization of the morphology and orientation of AMF fractures allows for the categorization of these fractures into more homogenous groups and the development of more consistent management algorithms.

Seismic Node Arrays for Enhanced Understanding and Monitoring of Geothermal Systems

Abstract Harnessing geothermal energy will likely play a critical role in reducing global CO2 emissions. However, exploration, development, and monitoring of geothermal systems remain challenging. Here, we explore how recent low-cost seismic node instrumentation advances might enhance geothermal exploration and monitoring. We show the results from 450 nodes deployed at a geothermal prospect in Cornwall, United Kingdom. First, we demonstrate how the nodes can be used to monitor the spatiotemporal and size distribution of induced seismicity. Second, we use focal mechanisms, shear-wave source polarities, and anisotropy to indicate how the dense passive seismic observations might provide enhanced insight into the stress state of the geothermal systems. All the methods are fully automated, essential for processing the data from many receivers. In our example case study, we find that the injection-site fracture orientations significantly differ from that of the crust above and the regional stress state. These observations agree well with fracture orientations inferred from independent well-log data, exemplifying how the nodes can provide new insight for understanding the geothermal systems. Finally, we discuss the limitations of nodes and the role they might play in hybrid seismic monitoring going forward. Overall, our results emphasize the important role that low-cost, easy-to-deploy dense nodal arrays can play in geothermal exploration and operation.

The Potential for Fracture Growth in Stepped Subglacial Topography as a Quarrying Mechanism

AbstractUnderstanding the rates and mechanisms of erosion by subglacial quarrying is a major unsolved problem in geomorphology. Stress enhancement due to load concentration on bedrock ledges between cavities is hypothesized to drive the growth of fractures. Prior work assumed the formation of vertically oriented tensile fractures at the downstream margins of cavities as the controlling process, but did not account for the evolution of the stress field as fractures lengthen, and in particular the dominance of the shearing mode at fracture tips. We used 2D finite element analysis and J‐integral methods to analyze stress intensity factors and fracture growth potentials at the tips of preexisting fractures in loaded bedrock steps, taking into account normal and shear components and measured rock strengths. By examining different step heights, step riser angles, rock types, prior fracture locations and orientations, and extents of ice‐rock contact zones, we identified some situations favorable for fracture growth, especially in brittle rock types. Typically, however, the growth direction will not be vertically downward but angled up‐glacier away from the step riser, a situation unfavorable for quarrying. Moreover, in many situations, the normal stress across fracture planes will be compressive. Non‐vertical step risers buttress the bedrock and also suppress fracture growth. In contrast, reducing the sizes of ice‐rock contact zones not only increases the loading magnitude, as previously recognized, but also increases intensification of tensile stress at the tips of fractures located just up‐glacier. Thus, larger cavities, and hence, fast sliding and low effective pressures, favor quarrying more strongly than previously recognized.

Utilizing well-reservoir pseudo-connections for multi-stage hydraulic fracturing modeling in tight gas saturated formations

Purpose. Research is aimed at integrating multi-stage hydraulic fracturing in horizontal wells with hydrodynamic simulation as a mandatory part of planning the mining of any shale oil or gas reservoir. Methods. Geological and hydrodynamic reservoir modeling is part of the research. The properties and geometries of the hydraulic fracture network and its representation in the dynamic reservoir model were assessed. The comparative characterization was carried out based on the two methods of fracture modeling: cell dimension reduction for explicit fracture modeling (LGR – local grid refinement) and implicit fracture modeling method, presented in this paper, with additional pseudo-connections between well and reservoir. Findings. A hydrodynamic model for low-permeable reservoir, produced by horizontal well, hydraulically fractured with 5 stages, has been generated. This model is calibrated to the production history and flowing bottom hole pressure by applying two methods of fracture modeling. Modeling results show that it is possible to replicate historical well production by using both methods. However, the proposed method with pseudo connections has several advantages compared to the generally accepted, local grid refinement (LGR) method. Originality. For the first time, a system of pseudo connections between well and reservoir was constructed to model a multi-stage hydraulic fracturing for a hydrodynamic model of tight reservoir. Hydrodynamic simulation results were refined and calibrated to the history of hydrocarbon production and flowing bottom hole pressure data using the pseudo-connections and LGR methods. The similarity of the results by applying LGR and pseudo-connections methods was revealed. Practical implications. The use of pseudo connections for hydraulic fracturing modeling can reduce simulation run time for cases where multi-stage hydraulic fracturing has already been carried out or is planned in the future. Additionally, the use of this method allows testing a larger number of realizations and scenarios, including hydraulic fracturing design (number of stages, size and conductivity of resulted fracture systems, fracture orientation, etc.), well placement and fracture growth relative to well trajectory. Also, there is no need to rebuild a model every time for each realization, as is the case with the LGR method.

Precise relative magnitude measurement improves fracture characterization during hydraulic fracturing

SUMMARY Microseismic monitoring is an important technique to obtain detailed knowledge of in-situ fracture size and orientation during stimulation to maximize fluid flow throughout the rock volume and optimize production. Furthermore, considering that the frequency of earthquake magnitudes empirically follows a power law (i.e. Gutenberg–Richter), the accuracy of microseismic event magnitude distributions is potentially crucial for seismic risk management. In this study, we analyse microseismicity observed during four hydraulic fracture treatments of the legacy Cotton Valley experiment in 1997 at the Carthage gas field of East Texas, where fractures were activated at the base of the sand-shale Upper Cotton Valley formation. We perform waveform cross-correlation to detect similar event clusters, measure relative amplitude from aligned waveform pairs with a principal component analysis, then measure precise relative magnitudes. The new magnitudes significantly reduce the deviations between magnitude differences and relative amplitudes of event pairs. This subsequently reduces the magnitude differences between clusters located at different depths. Reduction in magnitude differences between clusters suggests that some attenuation-related biases could be effectively mitigated with relative magnitude measurements. The maximum likelihood method is applied to understand the magnitude frequency distributions and quantify the seismogenic index of the clusters. Statistical analyses with new magnitudes suggest that fractures that are more favourably oriented for shear failure have lower b-value and higher seismogenic index, suggesting higher potential for relatively larger earthquakes, rather than fractures subparallel to maximum horizontal principal stress orientation.

Multiscale fracture, physical and mechanical properties of stromboli volcano (Italy) edifice

The physical, mechanical and fracture properties at Stromboli volcano have been integrated at multiple scales to understand whether the interplay between a presumed NE/SW rift zone and the Sciara del Fuoco (SDF) depression has resulted in a zone of weakness able to promote fracturing prone to flank instability. Multiscale fracture quantification by imaging via FracPaQ toolbox both fractures and sample scale fractures has been integrated with rock physics and rock mechanics experiments on cm-scale samples belonging to the Paleostromboli, Vancori, Neostromboli, Pizzo and Present Deposit volcanic cycles that have been taken from within and outside the rift zone. The structural changes to the edifice have been quantitively assessed by mapping at different scale fracture properties such density and orientation within and outside the rift zone allowing to identify the potential damaged zones that could reduce the edifice strength.Results indicate that basalt textures, microfracture density, porosity, chemical zoning and preferential alignments, despite lithologically dependent, can be related to the NE/SW zone of weakness at the regional scale and to collapsed volumes that have been subject to continuous intrusive activity. Numerical inversion models have been performed to cross correlate fracture density in the basalts at multiple scales.A link between microfracture density and seismic velocities has been also established via numerical modelling, allowing to interpret in terms of degree of fracturing the results of seismic tomographies at the field scale, providing a novel method to image crack damage evolution within the inner structure of the volcano edifice.

Correction of linear fracture density and error analysis using underground borehole data

Fracture data acquired from drill core and borehole image logs require corrections for the bias due to fracture orientation, that are usually achieved by the Terzaghi correction technique. Previous studies often approximate the wellbore as a one-dimensional scanline, assuming that the length of the core axis within the sampling range is equal to the scanline length. This study refers to the commonly used workflow as the original Terzaghi correction method which is known to perform poorly when the angle (θ) between the core axis and the fracture is small. To address this issue, we propose an extension of the Terzaghi correction method that also considers the core diameter and is a function of both the fractures and the host layer dipping angle. The new method resolves the fracture density problem by selecting a new direction for the scanline perpendicular to the fracture and calculating the projection length of the sampling space in this direction. The fracture spatial arrangements and observed number of sampled fractures mainly affect the performance of this new approach. However, possible errors in the new correction method pertaining to the equidistant fracture density should decrease with increasing number of sampled fractures. It is found that an acceptable correction range exists for equidistant fracture density, though, when the corrected density is not within the acceptable correction range, the observed sampled fractures will not be equal to the true observed value. This means the corrected fracture density would be in an unacceptable range of errors. Moreover, the new method can provide results within the acceptable range when the angle between the fracture and the core axis is less than 20°. At the same time, this new method is free from other disadvantages in the original Terzaghi correction method, particularly, when the ratio of layers’ thickness to the core diameter is low. Therefore, the improved approach presented here is especially applicable to thin layers (no more than two times the core diameter) and conditions where the angle between the fracture and the core axis is less than 20°, which can contribute to fracture density characterization in the subsurface.