Fracture Geometry Research Articles

Quantitative investigation into the relationship between the fracture geometry and the well production during near-wellbore temporary plugging and diverting fracturing

During near-wellbore temporary plugging and diverting fracturing (NWTDF), the old fractures can be plugged, and the new fractures can be generated and propagated along the direction perpendicular to the old fractures. The fracture geometry after NWTDF determines the stimulated volume and the well productivity. Studying the quantitative relationship between fracture geometry and well production during NWTDF is of great significance for NWTDF optimization. Based on the large-scale true tri-axial fracturing equipment, this work carried out the fracture propagation experiments of NWTDF. The experiment results confirmed the feasibility of forming diversion fractures by plugging the old fractures. The extended finite element method obtained the overall fracture geometry under various conditions. Moreover, based on the propagation pattern of fracture geometries, a reservoir seepage model was established and applied to predict oil well production. The results show that: (1) The fracture diversion radius (FDR) significantly affects well production. When the diversion radius increases from 20 m to 110 m, the well production increases by 17.2%. (2) When the FDR increases from 20 m to 50 m, the area of the pressure sweep region increases by about 7.5%; when the FDR increases to 80 and 110 m, the degree of the area and the productivity uplift is not apparent. There is an optimal value of the FDR. (3) Well productivity significantly increases with diversion frequency, while when it reaches 9, the degree of the well productivity uplift is small. The diversion frequency should be optimized to obtain a desirable stimulated volume. The research results provide a theoretical basis for the optimization design of NWTDF.

Geomechanics Modeling of Strain-Based Pressure Estimates: Insights from Distributed Fiber Optic Strain Measurements

Summary Rayleigh frequency shift distributed strain sensing (RFS-DSS) has been demonstrated as a potential technology for characterizing fracture geometries and optimizing the completion design in unconventional reservoirs. The combination of RFS-DSS strain and pressure gauge measurements has been reported recently in field applications (Dhuldhoya and Friehauf 2022; Haustveit and Haffener 2023) to characterize conductive fracture dimensions and production profiles. Haustveit and Haffener (2023) demonstrated a novel technique that uses RFS-DSS strain change during production, measured from a far-field observation well, to monitor the drain profile of a horizontal multistage well. The strain change and pressure change were strongly related during production, and this relationship was applied to continuously estimate pressure drawdown along the full length of the well. However, the sensitivity or influencing factors of the relationship between strain change and pressure change along the fiber are not yet fully understood. Therefore, the main objective of this study is to investigate the relationship between strain change and pressure change under various fractured reservoir conditions and provide guidelines for better utilizing this novel strain-pressure relationship to estimate conductive fractures and pressure profiles. We use a coupled geomechanics and fluid flow model to simulate the strain and pressure changes in the near-well and far-field regions during stable production and shut-in periods. A linear relationship is used to fit the strain change and pressure change data obtained from both producing and monitoring wells. We analyze the impact of various fracture properties [size and permeability of the stimulated reservoir volume (SRV) around fractures, fracture conductivity, fracture area, and skin factor] on the linear relationship based on the R2 value and fitting error. The relationship between the strain change and pressure change during the stable production obtained by our numerical study is consistent with the field measurements. The slope of strain change vs. pressure change during one day of production is significantly influenced by fracture properties. Overall, the monitoring well shows a stronger linear relationship than the producing well during both stable production and shut-in periods. A better linear relationship between the strain change and pressure change is associated with a larger fracture conductivity or larger fracture spacing scenario on both producing and monitoring wells during the stable production period. The cluster spacing affects the linear relationship between strain and pressure change during rock deformation. When cluster spacing is reduced, the nonlocal effect of deformation becomes more pronounced, resulting in a weaker linear relationship. During the shut-in period, the monitoring well exhibits a stronger linear relationship with a high R2 value and small fitting error compared to the producing well. The linear relationship obtained during the shut-in period is less reliable for the producing well. In cases of homogeneous fractures, where the fracture properties are uniform, the strain change and pressure change are similar, except for two outer fractures. This study provides a better understanding of the relationship between strain change and pressure change measured in the near-well and far-field regions during stable production and shut-in periods. The results of our study also demonstrate the potential for utilizing the RFS-DSS strain measurement to characterize the effective fracture and drainage dimensions.

Fracture Propagation of Multi-Stage Radial Wellbore Fracturing in Tight Sandstone Reservoir

Radial wellbore fracturing is a promising technology for stimulating tight sandstone reservoirs. However, simultaneous fracturing of multiple radial wellbores often leads to unsuccessful treatments. This paper proposes a novel technology called multi-stage radial wellbore fracturing (MRWF) to address this challenge. A numerical model based on the finite element/meshfree method is established to investigate the effects of various parameters on the fracture propagation of MRWF, including the azimuth of the radial wellbore, the horizontal stress difference, and the rock matrix permeability. The results show that previously created fractures have an attraction for subsequently created fractures, significantly influencing fracture propagation. A conceptual model is proposed to explain the variations in the fracture propagation of MRWF, highlighting three critical effect factors: the attraction effect, the orientation effect of the radial wellbore, and the deflection effect of the maximum horizontal principal stress. Fracture geometry is quantitatively assessed through the deviation distance, which indicates the radial wellbore’s ability to guide fracture propagation along its axis. As the azimuth increases, the deviation distances can either increase or decrease, depending on the specific radial wellbore layouts. Decreasing the horizontal stress difference and increasing the rock matrix permeability both increase the deviation distance.

DEM Investigation of Borehole Deformation and Stress Induced Fracture Geometry in Coal

DEM Investigation of Borehole Deformation and Stress Induced Fracture Geometry in Coal

Effects of orthogonal cleat structures on hydraulic fracture evolution behavior

Hydraulic fracturing operation as an effective enhancing coalbed gas production method is widely used in ultra-low permeability coal seam. However, complex geo-stresses and high heterogeneity between natural cleats structure lead to difficulty predicting hydraulic fracture patterns. Fracture evolution behavior for fracturing operation in coal seams requires a better understanding. In this study, a 2D model of hydraulic fracture propagation was built based on the cohesive zone model of finite element method. The effect of orthogonal cleat system, in-situ stress, dig angle and construction parameters on fracture geometries were main investigated. The main conclusions were as follows: (1) According to the interaction types between hydraulic fracture and cleat system, ladder-shaped fracture and H-shaped fracture geometry was summarized. The difference between them was whether there were continuous and small pressure fluctuation stages. (2) When the horizontal stress difference coefficient was lower and larger than 3/12, fracture geometry was prone to present Η shape and ladder shape respectively. Besides, the dimensionless fracture length and the dimensionless fracture extension aspect ratio of fracture were increasing with larger horizontal stress difference coefficient. (3) The favorable condition for fracture extension was that the dig angle was 45°. Hydraulic fracture tended to propagate along face cleats direction. (4) Larger fracture fluid displacement was beneficial to form more balanced hydraulic fracture geometry and promote large extension scale. As fracture fluid viscosity increased, the fracture geometries transformed from ladder shape to H shape.

Improving the technology for Inflow Profile Evaluation in horizontal Wells by temperature changes Due to calorimetric Mixing

The paper is devoted to the problem of increasing the effectiveness of temperature logging quantitative interpretation for the inflow profile evaluation in horizontal production wells draining heterogeneous reservoirs with low permeability. Such wells are characterized by an extremely uneven distribution of inflow along the length of the wellbore. One of the ways of quantitative interpretation of temperature logging is based on the effect of calorimetric mixing. It’s widely used to quantify the share of local producing intervals in the total flow rate.The low accuracy of interpretation is associated with the lack of reliable information about the temperature of the fluid flowing into the wellbore. The authors propose an estimate of this parameter based on the similarity of the behavior of the temperature field vs time in the near-wellbore zone of a reservoir during periods of stable production and the periods of the well shut-in. This relationship is confirmed by the results of modeling the temperature field of the “well – reservoir” system, taking into account changes in a wide range of reservoir permeability and thermal properties of the reservoir, the geometry of hydraulic fractures in the reservoir, the flowing fluids, as well as the parameters of the well production targets. The logging technology recommended by the authors involves the registration of several temperature profiles along the length of the wellbore at the beginning of the well production with the maximum rate and drawdown and during the well shut-in. Their integrated analysis based on the behavior of the temperature field features in time identified on the basis of modeling makes it possible to evaluate with a high degree of certainty the dynamics of the temperature of the gas-liquid mixture coming from reservoirs to the wellbore during production periods. This provides the required accuracy in the quantitative assessment of the inflow profile from mixing anomalies.The proposed approaches to the interpretation of thermograms are applicable in the analysis of the results of non-stationary temperature logging results in horizontal and vertical wells during the production from heterogeneous reservoirs both through perforation and multi-stage hydraulic fracturing.

Optimization of fracturing technology for unconventional dense oil reservoirs based on rock brittleness index

The concept of volume fracturing has revolutionized the conventional limits of low permeability, expanded the effective resource space, and significantly enhanced oil well production in tight oil reservoir development. This paper elucidates the mechanism of volume fracturing technology for tight sandstone reservoirs by considering multiple factors such as the initiation range of multi-fractures, influence of far-well horizontal principal stress on fracture initiation and propagation, degree of natural fractures development, and mechanical parameters of reservoir rock. Through simulation based on the mechanical parameters of reservoir rock, a comparative analysis was conducted between the model-calculated rock fracture pressure value and measured data from fracturing construction wells in the study area. The results revealed that there was a discrepancy within 10% between the model calculations and actual data. By simulating the effects of different injection volumes of fracturing fluid, pumping rates, and perforation methods on the fracture geometry, optimal design parameters for volume fracturing technology were obtained. Additionally, we propose optimization ideas and suggestions for construction parameters applicable to field operations. The simulation results indicate that a minimum recommended fluid volume scale exceeding 1800 m3 is advised for the reservoir. Based on frictional calculations, it is recommended to have an on-site construction rate not less than 18.0 m3/min along with 36–48 holes/section for perforation purposes. The numerical simulation research presented in this paper provides a theoretical reference basis and practical guidance for the application of fracturing network technology in tight sandstone reservoirs.

Evaluation of the combined influence of geological layer property and in-situ stresses on fracture height growth for layered formations

Fracture geometry is important when stimulating low-permeability reservoirs for natural gas or oil production. The geological layer (GL) properties and contrasts in in-situ stress are the two most important parameters for determination of the vertical fracture growth extent and containment in layered rocks. However, the method for assessing the cumulative impact on growth in height remains ambiguous. In this research, a 3D model based on the cohesive zone method is used to simulate the evolution of hydraulic fracture (HF) height in layered reservoirs. The model incorporates fluid flow and elastic deformation, considering the friction between the contacting fracture surfaces and the interaction between fracture components. First, an analytical solution that was readily available was used to validate the model. Afterwards, a quantitative analysis was performed on the combined impacts of the layer interface strength, coefficient of interlayer stress difference, and coefficient of vertical stress difference. The results indicate that the observed fracture height geometries can be categorized into three distinct regions within the parametric space: blunted fracture, crossed fracture, and T-shaped fracture. Furthermore, the results explained the formation mechanism of the low fracture height in the deep shale reservoir of the Sichuan Basin, China, as well as the distinction between fracture network patterns in mid-depth and deep shale reservoirs.

Fracturing Construction Curves and Fracture Geometries of Coals in the Southern Qinshui Basin, China: Implication for Coalbed Methane Productivity.

Hydraulic fracturing technology has become a common practice to enhance the permeability of coal seams, and its effectiveness significantly impacts the productivity of coalbed methane (CBM) wells. In this study, multiple data sets, including fracturing reports, productivity data, and microseismic monitoring, were utilized to analyze the factors influencing fracturing effectiveness and gas well production at the southern margin of the Qinshui Basin, China, especially the Zhengzhuang and Fanzhuang blocks. Statistics revealed that the fracturing displacement, liquid consumption, and sand consumption were 8 m3/min, 17.69-1386.52 m3 (averaging 728.42 m3), and 28.5-46.1 m3 (averaging 40 m3), respectively. There were differences in the types of fracturing curves among blocks or well groups, and the natural fracture system was identified as the key factor affecting their characteristics. The coal seams with high density of microfractures in Zhengzhuang reduce the fracture threshold of reservoirs during hydraulic fracturing, resulting in a lower fracture response ratio than that of Fanzhuang (71.0 vs 80.3%). Well groups with higher microfracture width in coal seams (Group-ZC and DS) experienced a further reduction in fracture response (averaging 67.2 vs 80.3%), and the connection of hydraulic fractures (HFs) with these high-permeability microfractures lead to an increase in the proportion of fluctuating fracturing curves (averaging 52.2 vs 33.6%). Regional structural features and fracturing effectiveness jointly affected the production of CBM wells. The productivity in Zhengzhuang was lower than that in Fanzhuang due to the highly developed faults and deeply buried coal seams. Shallow coal seams with a high width of microfractures and a low-stress environment were easily supported by a proppant, forming a complex HF network and yielding a high productivity (Group-ZC and DS). For other deeper well groups, proppant migration became unfavorable once high-angle and complex branch HF clusters formed in coal seams, leading to local low-efficiency wells and fluctuating fracturing curves.

A Novel Model of Hydraulic Aperture for Rough Single Fracture: Insights From Fluid Inertial and Fracture Geometry Effects

A Novel Model of Hydraulic Aperture for Rough Single Fracture: Insights From Fluid Inertial and Fracture Geometry Effects

Geometry Analysis of Penang Island Faults Based on Satellite Gravity Data

Abstract The gravity method is commonly used in geophysics for fault mapping. This method provides an overview of the subsurface density distribution. When applied to fault areas, the density gradient contrast can be used to map the fault geometry structure. The research area for this study is Penang Island, Malaysia, which is predominantly composed of granite. The Penang Island granite formation was created during the Triassic period, approximately 209 to 22 million years ago (Kwan and Yap, 1986). It underwent uplift during the Oligocene-Miocene period, exposing the previously buried granite. The second formation is a quaternary sediment that is believed to have formed during the Pleistocene and Holocene (Kamaluddin, 1990). Penang Island has 14 faults scattered throughout, with 5 main faults in the middle (Ong, 1993). The study aimed to determine the fracture geometry using the gravity method. The analysis revealed two main rock types: granite with a density range of 2-2.8 gr/cm3 and quaternary sediment with a density of 1.85-2 gr/cm3. Fault geometry analysis was conducted using the SVD method on four passages in Penang Island to identify fault types. The results showed six normal faults and seven thrust faults. Faults No. 3, 4, 8, 9, 12, and 13 are predicted to be normal faults, while Faults No. 1, 2, 5, 7, 10, 11, and 14 are predicted to be thrust faults. The dominant direction of the fault is North-South. The fault geometry on North Pluton has an average depth of 250 m with an average dip angle of 68°, while the fault on South Pluton has a depth of over 400 m with an average dip angle of 65°.

A heat mining strategy for the potential Enhanced Geothermal System of the Acoculco Caldera Complex, Puebla (Mexico): A numerical approach based on Multiple Interacting Continua

As the world faces a transition to low-carbon electricity, energy markets have witnessed a fast expansion of Variable Renewable Energy, such as solar and wind power. In contrast, the installed capacity of geothermal electricity has increased with at a much lower rate. Continuous innovation is required to maintain geothermal electricity as a cost-competitive technology that helps building flexible power generation systems. Here we propose a heat mining setup for the promissory Enhanced Geothermal System (EGS) of the Acoculco caldera complex, which hosts a heat source in low permeability rocks. The conceptual model of the EGS reservoir consists of a fractured-porous layer between impermeable confining beds. An injection-production triplet is located in line with a fault plane that intersects the model area. Under the assumption of hydraulic stimulation to the fault zone, flow of the injection-production system restricts to a fracture network with secondary and variable permeability. Mass and heat transport is modeled following the Multiple Interacting Continua method with the software TOUGH2. We evaluate the performance of the heat mining system considering water and CO2 as working fluids for a given flow rate. We also evaluate the impact of fracture spacing in the reservoir performance. Results show that for a reservoir temperature of 300 °C, the CO2-based system experiences considerable adverse flow conditions that demands a higher pressure differential between the producer and injector (about 60 bar higher than the water-based reservoir). Likewise, the low heat capacity of CO2 imply a considerable limitation for heat mining. While for the water-based reservoir the cooling front extends throughout the entire reservoir at 30 yr of operation, for CO2 this happens in only about 60%. Additionally, the energy extracted per unit time in the water-based reservoir results more than twice the energy extracted with CO2. Finally, our numerical results show that fracture spacings in the range of 10 to 75 m behave similarly in terms of heat mining performance; decreasing the heat exchange area by increasing the fracture spacing from 10 to 75 m produces a minor impact under the assumption of high permeability fractures. Additional constrains for the fracture network, such as geometry, effective porosity and permeability of both fractures and rock matrix, have to be investigated in future research to better understand the possible performance of the production system.

Numerical analysis of coupled thermal–hydraulic processes based on the embedded discrete fracture modeling method

The enhanced geothermal system (EGS) technology is considered an effective way to extract energy from deep hot dry rock (HDR) geothermal resources, which involves the coupling of complex thermal–hydraulic processes in fractured geological media. In this work, we propose a numerical approach based on the concept of embedded discrete fracture modeling method (EDFM), to estimate heat production performance from the EGS. We validated the method by comparing the outputs of our numerical models with experimental data and analytical solutions. A simplified, idealized two-dimensional model with discrete fractures was applied to gain insights on mass and heat transfer mechanisms expected under field conditions. Simulation results indicated that isolated and dead-end fractures have little influence on the overall performance of EGS, under the initial and boundary conditions of our numerical experiments (e.g., fracture density and permeability differences between fractures and matrix). It emerges that geometry and hydraulic transmissivity of fractures are key factors in controlling the effectiveness of the heat exchange between host rocks and circulating fluids. This work emphasizes the importance of implementing increasingly reliable descriptions of the fluid-dynamic and thermodynamic behavior of fractures, to increase the confidence in the numerical assessment of the performance of EGS installations.

Changes in mechanical properties and surface microstructure of shale organic matter after coupling supercritical carbon dioxide with water

Supercritical carbon dioxide (ScCO2) fracturing technology has been increasingly emphasized in the development of unconventional oil and gas resources due to its advantages of anhydrous fabrication of complex seam networks and geological sequestration of CO2. However, previous studies have mostly focused on the geometry, number, and type of inorganic mineral fractures, and rarely paid attention to the changes in the seepage structure within organic matter (OM). To characterize the nanoscale microstructural changes of OM induced by H2O-ScCO2, this study obtained the variation rule of mechanical properties of OM with adsorbed water saturation based on nanoindentation test, and the continuous change of elastic modulus and morphology of the OM in the same region after dry, water-wet, and water-ScCO2 treatments was compared by atomic force microscopy (AFM). Elastic modulus and hardness of OM were calculated by Oliver-Pharr and Hertz methods, and the average roughness, root mean square roughness, and kurtosis were obtained based on 3D morphology. The results showed that elastic modulus and hardness were negatively and nonlinearly correlated with water saturation. Although the AFM-measured elastic modulus of OM microphases of the dry, water-wet, and water-ScCO2-treated shale were all highly discrete and non-homogeneous, they were generally normally distributed, and the mean values of the elastic modulus decreased sequentially. It is determined that water-ScCO2 coupling make OM matrix undergo superimposed dissolution. It is shown that ScCO2 and water synergistically change the microstructure of shale OM, and the weakening of mechanical properties and the increase of surface roughness are very favorable for geological sequestration and long-term storage of CO2.

Investigation of Effective Fracture Height Using Strain Responses in a Vertical Monitoring Well during a Well Interference Test

Summary Understanding and characterizing the effective hydraulic fracture height are critical for optimizing completion design and well performance in unconventional reservoirs. Rayleigh frequency shift distributed strain sensing (RFS-DSS) data provide crucial information about the fracture geometry by measuring the strain change along the fiber. Recently, the strain data from the vertical monitoring well [VMW; Boxwood 5 Pilot Hole (B5PH)] at Hydraulic Fracture Test Site 2 (HFTS-2) was collected during a well interference test conducted on two neighboring horizontal wells [Boxwood 3H (B3H) and Boxwood 4H (B4H)] in September 2020. However, this data set was overlooked and not comprehensively analyzed. Consequently, the valuable information that this data may provide remains unexplored. The objective of this study is to determine how to interpret this vertical strain data and assess its potential to provide insights into the effective fracture height generated in the horizontal wells. To understand the measured strain data, we have developed a coupled fluid flow and geomechanics model to simulate the vertical strain responses observed during production and the well interference test. The characteristics of the strain responses are thoroughly analyzed to establish guidelines for identifying the upper and lower tips of the effective fracture in different fracture geometry scenarios. In addition, field-measured data are examined, and a history-matching process is conducted by comparing the numerical matching results with the observed data to identify the effective fracture height. Furthermore, the pressure gauge data are analyzed and compared with the strain data results to further validate the findings. The study has demonstrated that vertical strain measurements obtained from a VMW can be used to determine the effective fracture height. Large strain responses, characterized by both negative and positive peaks, are observed near the tips of the effective fractures. The upper and lower tips of the effective fracture can be identified by examining the locations of zero-strain change. The magnitude of strain response is affected by the distance between the fracture and the fiber. It is worth noting that the locations where the absolute value of the derivative of fracture conductivity changes abruptly correspond to the positions of the fracture tips. Furthermore, we study and history match the field-measured vertical strain change in HFTS-2 data sets. The pressure gauge data are analyzed to further validate our findings. The effective fracture height determined from the strain measurements falls within the range of 11,360–11,616 ft, which is consistent with the values obtained from pressure gauges (11,360–11,635 ft). Specifically, for B4H, the effective fracture height was determined to be 256 ft at a distance of 330 ft away at the time of data acquisition. Overall, the strain measurements provide valuable, time-dependent insights into the effective fracture height and the active drainage interval.

A fluid–solid coupling model for hydraulic fracture of deep coal seam based on finite element method

The fluid–solid coupling effect is more pronounced in the process of deep coal seam development compared to shallow coalbed methane, exerting a greater influence on production, and cannot be disregarded. Throughout the extraction process, the interaction between effective stress and gas desorption triggers deformation within the coal seam, leading to dynamic changes in both porosity and permeability. This paper has developed a fully coupled gas flow and deformation model that contains the coal matrix and discrete fractures to describe the dynamic gas seepage behavior and deformation of deep coal seams within a coupled wellbore–hydraulic fractures–matrix system. The model's validity is corroborated through the examination of fracture aperture, employing the finite element numerical simulation capabilities of COMSOL Multiphysics. Subsequent to the model's validation, an in-depth investigation into the permeability and production variations under diverse parametric conditions is conducted. This analysis also encompasses the assessment of hydraulic fracture geometry's impact. The simulation outcomes reveal that the permeability alterations during coal seam development are subject to the counteracting influences of gas desorption and effective stress. Moreover, it is observed that an increase in the Langmuir volume strain constant and initial porosity correlates with enhanced production, whereas a diminution in the hydraulic fracture compression coefficient leads to increased cumulative production. Notably, the optimal production is attained when hydraulic fractures are oriented vertically yet asymmetrically relative to the horizontal well.

Geothermal energy potential of basement hot springs: Case study of Ulu Slim (Perak, Malaysia)

Interest in geothermal energy as a clean, renewable and stable source of energy is mounting as part of the strive towards carbon emissions reduction and transition away from fossil fuels. Hot springs occur in locations of active hydrothermal systems that may have exploitation potential and this paper assesses the potential of Ulu Slim hot-spring, the warmest of some 60 basement hot-springs reported across Peninsular Malaysia. Available data and analogue inferences i.e., hot-spring surface temperature and flowrate, applicable ranges in geothermal gradients, geothermometer indications of source temperature, hydraulic head differences related to surface topography, indicative and tentative fault and fracture dimensions, geometry and distribution, are summarized and supplemented by conceptual hydrodynamic- and thermodynamic-model calculations to bracket the possible range in key subsurface parameters like source depth and geometry and properties of the fracture system that control extractable heat. Results are then used in another mathematical model that simulates the heat-extraction and electric power potential of hypothetical wells drilled into the hot-spring source, supported by injector wells (re-injecting the cool waste stream from the powerplant). Model outcomes suggest that premature cooling due to fluid circulation through narrow fracture/fault corridors is a significant risk. Overall, study results suggest that utilizing the geothermal heat of hot springs like Ulu Slim for electric power generation may be not so straightforward. Maybe the search for attractive geothermal locations should be less guided by hot-spring locations but instead, driven by proximity to infrastructure and electricity demand.

Advanced Deep Learning for microseismic events prediction for hydraulic fracture treatment via Continuous Wavelet Transform

Understanding hydraulic fracture propagation events would enable operators to estimate the fracture geometry, understand formation/fracture interactions, and estimate the total microseismic events cloud. This paper introduces a new method for understanding the dynamic fracture propagation events using a signal processing technique. Detection of the dynamic fracture event using continuous wavelet transform (CWT) is used to train a deep learning model with microseismic events to predict this cloud for every hydraulic fracture job. The deep learning model is used for the same formation. The CWT for treatment pressure is a convolution process that involves the application of a wavelet signal to the acquired pressure signal in a continuous manner. The wavelet is stretched, or compressed, and is moved along the acquired pressure signal, acting as a generic microscope to highlight small changes in the treating pressure signal. Using CWT as a mathematical microscope to discern diverse signals has been adopted by numerous engineering and medical applications since the 1990s.A normalized CWT scalogram for fracture-treating pressure is thus created as a unique representation of each fracture propagation mode in the hydraulic fracturing job. The new technique is calibrated with several fracture simulation runs and real field data using the previous techniques like moving reference point (MRP). That previous technique which has been previously validated through fracture simulation, is used as a calibration for the new normalized CWT scalogram technique. The technique was finally calibrated by comparing it with micro-seismic events recorded by the Marcellus Shale Energy and Environment Laboratory (MSEEL).The results of this comparison were exceptionally accurate. It can be used to train a deep learning model that can be used to estimate the cloud of microseismic events for hydraulic fracture jobs in Marcellus shale. The new deep learning framework uses CWT to convert the treating pressure during hydraulic fracture propagation to dimensionless representation (normalized CWT scalogram) which acts as a mathematical microscope for the fracture treating pressure on different wavelet stretch or compressions, enabling the detection of the major changes in the treating pressure then train the deep learning model to estimate microseismic events cloud.

Geomechanical modeling to assess the injection-induced fracture slip-potential and subsurface stability of the Cambro-Ordovician reservoirs of Hassi Terfa field, Algeria

The in-situ stress state and the distribution of the critically stressed fractures have significant implications on optimum wellbore placement, production enhancement, fluid injection, and induced seismicity which largely influence the reservoir management strategies. This study presents a comprehensive geomechanical modeling to infer the likelihood of shear slippage of the optimally oriented weak planes in response to water injection in the deep Paleozoic oil reservoirs from the Hassi Terfa field, central Algerian Sahara. The ‘B-quality’ compressive failures, i.e., breakouts from the acoustic image log indicate the maximum horizontal stress azimuth as N114°E. The inferred in-situ stress magnitudes indicate a strike-slip tectonic regime in the study area. The reservoir is generally tight (porosity <8 %, permeability <0.4 mD) due to extensive silica cementation, however pre-existing closed to partially open natural fractures of variable geometries are identified on cores, thin sections, and image logs. The stress-based slip assessment indicates that none of the fracture geometries is critically stressed and hydraulically conductive at the initial reservoir stress state. The onset of slip on the critically oriented vertical fractures can initiate at 1200 psi of fluid injection at the reservoir level of ∼3500 m. The E-W to EES-WWN oriented fractures, parallel to the maximum horizontal stress azimuth, have a higher likelihood of being critically stressed during injection and therefore can contribute to the permeability enhancement. We restrict the practical injection threshold at 3000 psi, which can create tensile failures on the shale caprocks. We infer that the NE-SW and NNE-SSW striking, steeply dipping fractures and regional faults being perpendicular or at high angles to the regional maximum horizontal stress azimuth, are the most stable ones and therefore, less likely to slip within the practical injection limit.

EVALUATING SHORT-TERM OUTCOMES POST- INTRA-ARTICULAR CALCANEAL FRACTURE FIXATION VIA A SINUS TARSI APPROACH IN A NON-EXCLUSIVELY SELECTED COHORT

AimsManagement of intra-articular calcaneal fractures remains a debated topic in orthopaedics, with operative fixation often held in reserve due to concerns regarding perioperative morbidity and potential complications. The purpose of this study was to identify the characteristics of patients who developed surgical complications to inform the future stratification of patients best suited to operative treatment for intra-articular calcaneal fractures and those in whom surgery was highly likely to produce an equivocal functional outcome with potential post-operative complications.MethodsAll patients who underwent open reduction and internal fixation of calcaneal fractures utilizing the Sinus Tarsi approach between March 2014 and July 2018 were identified using theatre records. Patient imaging was used to assess pre- and post-operative fracture geometry with Computed Tomography (CT) used for pre-operative planning. Each patient's clinical presentation was established through retrospective analysis of medical records. Patients provided verbal consent to participation and patient reported outcome measures were recorded using the Maryland Foot Score.ResultsFifty-eight intra-articular calcaneal fractures (fifty-three patients including five bilateral, mean age = 46.91 years) were included. Forty-nine patients were injured as a result of a fall from a height (92.4%). Mean time from presentation to surgery was 3.23 days (range 0–21). Mean Maryland Foot score was found to be 77.6 (+/− 16.22) in forty-five patients. Five patients (9.4%) had wound complications; two superficial (3.7%) and three deep (5.6%).ConclusionIntra-articular fractures of the calcaneus should be considered for surgical intervention in order to improve long-term functional outcomes. The Sinus Tarsi approach provides the potential to decrease the operative complication rate whilst maintaining adequate fixation, however, the decision to surgically manage these fractures should be carefully balanced against the risk of post-operative complications. This increased risk of complication associated with smoking may tip the balance against benefit from surgical management.