The Impact of Rock Properties and Stress Shadowing on the Hydraulic Fracture Properties in Marcellus Shale

2019 ◽  
Author(s):  
Mohamed El Sgher ◽  
Kashy Aminian ◽  
Samuel Ameri
Keyword(s):  
Hydraulic Fracture ◽  
Marcellus Shale ◽  
Rock Properties ◽  
Fracture Properties ◽  
The Impact

Impact of the Cluster Spacing on Hydraulic Fracture Conductivity and Productivity of a Marcellus Shale Horizontal Well

2021 ◽  
Author(s):  
Mohamed El Sgher ◽  
Kashy Aminian ◽  
Ameri Samuel
Keyword(s):  
Hydraulic Fracture ◽  
Marcellus Shale ◽  
Technical Information ◽  
Gas Production ◽  
Production Performance ◽  
Valuable Insight ◽  
Fracture Conductivity ◽  
Fracture Properties ◽  
Gas Recovery ◽  
The Impact

Abstract The objective of this study was to investigate the impact of the hydraulic fracturing treatment design, including cluster spacing and fracturing fluid volume on the hydraulic fracture properties and consequently, the productivity of a horizontal Marcellus Shale well with multi-stage fractures. The availability of a significant amount of advanced technical information from the Marcellus Shale Energy and Environment Laboratory (MSEEL) provided an opportunity to perform an integrated analysis to gain valuable insight into optimizing fracturing treatment and the gas recovery from Marcellus shale. The available technical information from a horizontal well at MSEEL includes well logs, image logs (both vertical and lateral), diagnostic fracture injection test (DFIT), fracturing treatment data, microseismic recording during the fracturing treatment, production logging data, and production data. The analysis of core data, image logs, and DFIT provided the necessary data for accurate prediction of the hydraulic fracture properties and confirmed the presence and distribution of natural fractures (fissures) in the formation. Furthermore, the results of the microseismic interpretation were utilized to adjust the stress conditions in the adjacent layers. The predicted hydraulic fracture properties were then imported into a reservoir simulation model, developed based on the Marcellus Shale properties, to predict the production performance of the well. Marcellus Shale properties, including porosity, permeability, adsorption characteristics, were obtained from the measurements on the core plugs and the well log data. The Quanta Geo borehole image log from the lateral section of the well was utilized to estimate the fissure distribution s in the shale. The measured and published data were utilized to develop the geomechnical factors to account for the hydraulic fracture conductivity and the formation (matrix and fissure) permeability impairments caused by the reservoir pressure depletion during the production. Stress shadowing and the geomechanical factors were found to play major roles in production performance. Their inclusion in the reservoir model provided a close agreement with the actual production performance of the well. The impact of stress shadowing is significant for Marcellus shale because of the low in-situ stress contrast between the pay zone and the adjacent zones. Stress shadowing appears to have a significant impact on hydraulic fracture properties and as result on the production during the early stages. The geomechanical factors, caused by the net stress changes have a more significant impact on the production during later stages. The cumulative gas production was found to increase as the cluster spacing was decreased (larger number of clusters). At the same time, the stress shadowing caused by the closer cluster spacing resulted in a lower fracture conductivity which in turn diminished the increase in gas production. However, the total fracture volume has more of an impact than the fracture conductivity on gas recovery. The analysis provided valuable insight for optimizing the cluster spacing and the gas recovery from Marcellus shale.

Petroelastic and geomechanical classification of lithologic facies in the Marcellus Shale

2015 ◽  
Vol 3 (1) ◽  
pp. SA51-SA63 ◽  
Author(s):  
Dario Grana ◽  
Kristen Schlanser ◽  
Erin Campbell-Stone
Keyword(s):  
Marcellus Shale ◽  
Expectation Maximization Algorithm ◽  
Rock Physics ◽  
Rock Properties ◽  
Geomechanical Properties ◽  
Facies Classification ◽  
Well Location ◽  
Input Variables ◽  
Shale Oil Reservoirs ◽  
The Impact

Log-facies classification at the well location allows determination of the number of facies, the facies definition, and the correlation between facies and rock properties along the well profile. In unconventional reservoirs, because of the necessity for hydraulic fracturing in shale gas and shale oil reservoirs, facies classification should account for petroelastic and geomechanical properties. We developed a facies classification methodology based on the expectation-maximization algorithm, a statistical method that allows finding the most likely facies classification and the associated probability distribution, given the set of geophysical measurements in the borehole. We applied the proposed workflow to a complete set of well logs from the Marcellus shale and developed the corresponding facies classification from log properties measured and computed in three different domains: petrophysics, rock physics, and geomechanics. In thne preliminary well-log and rock-physics analysis, we identify three main lithofacies: limestone, shale, and sandstone. The application of the classification method provided the vertical sequence of the three lithofacies and their pointwise probability of occurrence. A sensitivity analysis was finally evaluated to investigate the impact of the number of input variables on the classification and the effects of cementation and kerogen.

Laboratory demonstration of hydraulic fracture height growth across weak discontinuities

Geophysics ◽  
2018 ◽  
Vol 83 (2) ◽  
pp. MR93-MR105 ◽  
Author(s):  
Pengju Xing ◽  
Keita Yoshioka ◽  
Jose Adachi ◽  
Amr El-Fayoumi ◽  
Andrew P. Bunger
Keyword(s):  
Fracture Toughness ◽  
Hydraulic Fracture ◽  
Fluid Pressure ◽  
Height Growth ◽  
Rock Properties ◽  
Vertical Fracture ◽  
Parametric Space ◽  
Fracture Height ◽  
Stress Contrast ◽  
The Impact

Decades of research have led to numerous insights in modeling the impact of stresses and rock properties on hydraulic fracture height growth. However, the conditions under which weak horizontal interfaces are expected to impede height growth remain for the most part unknown. We have developed an experimental study of the impact of weak horizontal discontinuities on hydraulic fracture height growth, including the influences of (1) abrupt stress contrasts between layers, (2) material fracture toughness, and (3) contrasts of stiffness between the reservoir and bounding layers. The experiments are carried out with an analog three-layered medium constructed from transparent polyurethane, considering toughnesses resisting vertical fracture growth. There are four observed geometries: containment, height growth, T-shape growth, and the combination of height growth and T-shape. Results are developed in a parametric space embodying the influence of the horizontal stress contrast, vertical stress, and horizontal barrier stress contrast, as well as the fluid pressure. The results indicate that these cases fall within distinct regions when plotted in the parametric space. The locations in the parametric space of these regions are strongly impacted by the vertical fracture toughness: Increasing the value of the vertical interface fracture toughness leads to a suppression of height growth in favor of containment and T-shaped growth. Besides providing detailed experimental data for benchmarking 3D hydraulic fracture simulators, these experiments show that the fracture height is substantially less than would be predicted in the absence of the weak horizontal discontinuities.

Integration of Borehole Acoustic Reflectivity Survey and Fracture Pressure Analysis to Determine Properties of Far-Field Heterogeneities During Stimulation in Tight Reservoirs

2021 ◽  
Author(s):  
Dmitriy Abdrazakov ◽  
Evgeniy Karpekin ◽  
Anton Filimonov ◽  
Ivan Pertsev ◽  
Askhat Burlibayev ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Rock Properties ◽  
Production Data ◽  
Far Field ◽  
Suggested Approach ◽  
Fracture Properties ◽  
Fracture Pressure ◽  
Heterogeneous Features ◽  
Pressure Analysis

Abstract The presence of conductive and extended heterogeneous features not connected to the wellbore and located beyond the investigation depths of standard characterization tools can be the reason for unexpected loss of net pressure during stimulation treatments due to the hydraulic fracture breakthrough into these heterogeneous areas. In current field practice, if such breakthrough occurs, it is considered as bad luck without the possibility of the quantitative analysis. This mindset can be changed in favor of the stimulation and reservoir management success using an approach that ties the thorough fracture pressure analysis with the output of the specific acoustic reflectivity survey capable of identifying position, shape, and orientation of far-field heterogeneous features. The approach consists of four steps and is applicable to cases when the hydraulic fracture experiences breakthrough into the heterogeneity. First, before the stimulation treatments, at the reservoir characterization stage, a borehole acoustic reflectivity survey is run. Gathered data are interpreted and visualized according to a specific workflow that yields the image of the heterogeneous areas located around the wellbore in the radius of several tens of meters. Second, the hydraulic fracturing treatment is performed, and fracture pressure analysis is performed, which identifies the pressure drops typical for the breakthrough. Third, after the breakthrough into the heterogeneity is confirmed, the distance to this heterogeneity is used as a marker for calibration of the fracture properties and geometry. Finally, the post-stimulation pressure and production data are used to define the properties of the heterogeneous features, such as conductivity and approximate dimensions. The comprehensive field application example of the suggested approach confirmed its effectiveness. For the tight carbonate formations, the heterogeneity in a form of fracture corridor was revealed by the acoustic reflectivity survey at least 20 m away from the wellbore. The breakthrough into this heterogeneity was observed during the acid fracturing treatment. The distance to the heterogeneity and observed pumping time to breakthrough were used as markers characterizing fracture propagation; reservoir and rock properties were adjusted using a fracturing simulator to obtain this fracture propagation. Finally, the post-stimulation production data were analyzed to determine infinite conductivity of the fracture corridor and quantify its extent downward. Data gathered during reservoir and hydraulic fracture properties calibration allowed for optimization of stimulation strategy of the target layer throughout the field; the information about the heterogeneity’s properties allowed for optimization of the completion and reservoir development strategy.

Evaluation of Hydraulic Fracturing Treatment with Microseismic Data Analysis in A Marcellus Shale Horizontal Well

2021 ◽  
Author(s):  
Mohamed El Sgher ◽  
Kashy Aminian ◽  
Samuel Ameri
Keyword(s):  
Reservoir Simulation ◽  
Hydraulic Fracture ◽  
Horizontal Well ◽  
Marcellus Shale ◽  
Production Performance ◽  
Well Logs ◽  
Well Log ◽  
Fracture Properties ◽  
The Core ◽  
Reservoir Simulation Model

Abstract The objective of this study was to perform an integrated analysis to gain insight for optimizing fracturing treatment and gas recovery from Marcellus shale. The analysis involved all the available data from a Marcellus Shale horizontal well which included vertical and lateral well logs, hydraulic fracture treatment design, microseismic, production logging, and production data. A commercial fracturing software was utilized to predict the hydraulic fracture properties based on the available vertical and lateral well logs data, diagnostic fracture injection test (DFIT), fracture stimulation treatment data, and microseismic recordings during the fracturing treatment. The predicted hydraulic fracture properties were then used in a reservoir simulation model developed based on the Marcellus Shale properties to predict the production performance. In this study, the rock mechanical properties were estimated from the well log data. The minimum horizontal stress, instantaneous shut-in pressure (ISIP), process zone stress (PZS), and leak-off mechanism were determined from DFIT analysis. The stress conditions were then adjusted based on the results of microseismic interpretations. Subsequently, the results of the analyses were used in the fracturing software to predict the hydraulic fracture properties. Marcellus Shale properties and the predicted hydraulic fracture properties were used to develop a reservoir simulation model. Porosity, permeability, and the adsorption characteristics were estimated from the core plugs measurements and the well log data. The image logs were utilized to estimate the distribution of natural fractures (fissures). The relation between the formation permeability and the fracture conductivity and the net stress (geomechanical factors) were obtained from the core plugs measurements and published data. The predicted production performance was then compared against production history. The analysis of core data, image logs, and DFIT confirmed the presence of natural fractures in the reservoir. The formation properties and in-situ stress conditions were found to influence the hydraulic fracturing geometry. The hydraulic fracture properties are also impacted by stress shadowing and the net stress changes. The production logging tool results could not be directly related to the hydraulic fracture properties or natural fracture distribution. The inclusion of the stress shadowing, microseismic interpretations, and geomechanical factors provided a close agreement between the predicted production performance and the actual production performance of the well under study.

The Impact of Rock Properties on Acid Jetting in Carbonate Rocks: An Experimental Study

2016 ◽  
Author(s):  
V. Ndonhong ◽  
E. Belostrino ◽  
D. Zhu ◽  
A. D. Hill ◽  
R. E. Beckham ◽  
...  
Keyword(s):  
Experimental Study ◽  
Carbonate Rocks ◽  
Rock Properties ◽  
The Impact

scholarly journals Evolution of a sand-rich submarine channel-lobe system and impact of mass-transport and transitional flow deposits on reservoir heterogeneity: Magnus Field, northern North Sea

2021 ◽  
pp. petgeo2020-095
Author(s):  
Michael J. Steventon ◽  
Christopher A-L. Jackson ◽  
Howard D. Johnson ◽  
David M. Hodgson ◽  
Sean Kelly ◽  
...  
Keyword(s):  
Mass Transport ◽  
North Sea ◽  
Fluid Pressure ◽  
Transitional Flow ◽  
Rock Properties ◽  
Sweep Efficiency ◽  
Content Type ◽  
Supplementary Material ◽  
Northern North Sea ◽  
The Impact

The geometry, distribution, and rock properties (i.e. porosity and permeability) of turbidite reservoirs, and the processes associated with turbidity current deposition, are relatively well known. However, less attention has been given to the equivalent properties resulting from laminar sediment gravity-flow deposition, with most research limited to cogenetic turbidite-debrites (i.e. transitional flow deposits) or subsurface studies that focus predominantly on seismic-scale mass-transport deposits (MTDs). Thus, we have a limited understanding of the ability of sub-seismic MTDs to act as hydraulic seals and their effect on hydrocarbon production, and/or carbon storage. We investigate the gap between seismically resolvable and sub-seismic MTDs, and transitional flow deposits on long-term reservoir performance in this analysis of a small (<10 km radius submarine fan system), Late Jurassic, sandstone-rich stacked turbidite reservoir (Magnus Field, northern North Sea). We use core, petrophysical logs, pore fluid pressure, quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN), and 3D seismic-reflection datasets to quantify the type and distribution of sedimentary facies and rock properties. Our analysis is supported by a relatively long (c. 37 years) and well-documented production history. We recognise a range of sediment gravity deposits: (i) thick-/thin- bedded, structureless and structured turbidite sandstone, constituting the primary productive reservoir facies (c. porosity = 22%, permeability = 500 mD), (ii) a range of transitional flow deposits, and (iii) heterogeneous mud-rich sandstones interpreted as debrites (c. porosity = <10%, volume of clay = 35%, up to 18 m thick). Results from this study show that over the production timescale of the Magnus Field, debrites act as barriers, compartmentalising the reservoir into two parts (upper and lower reservoir), and transitional flow deposits act as baffles, impacting sweep efficiency during production. Prediction of the rock properties of laminar and transitional flow deposits, and their effect on reservoir distribution, has important implications for: (i) exploration play concepts, particularly in predicting the seal potential of MTDs, (ii) pore pressure prediction within turbidite reservoirs, and (iii) the impact of transitional flow deposits on reservoir quality and sweep efficiency.Supplementary material:https://doi.org/10.6084/m9.figshare.c.5313860

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