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Abstract Completion designs for hydraulic stimulation of shale-gas reservoirs frequently accounts for vertical growth of the treatment volume in the formation. Where vertical growth is expected, wells are drilled near the base of the reservoir optimizing the distribution of proppant upwards. Other treatments may seek to transport treatment fluid across a lithologic barrier, effectively trying to "treat two formations for the price of one." Vertical growth needs to occur under controlled conditions, undesirable growth leads to a potential creation of pathways for treatment fluids to leak out of formation, or worse pathways allowing undesirable fluids to flow into formation. In either case, this could lead to a loss in optimization for production. To better understand vertical growth characteristics of hydraulic treatment volumes, microseismic monitoring arrays deployed downhole just above the formation provide a good discriminant for vertical growth of events. Further characterization of this growth can be accomplished through Seismic Moment Tensor Inversion (SMTI), when a sufficient angular distribution of multiple downhole arrays detects the microseismicity. SMTI can distinguish the source type of the mechanisms (e.g. openings, closures, shear, etc.) and the orientations of the activated structures, allowing for a more complete picture of the failure process. In the example provided, different stages of stimulation in the Marcellus shale formation are examined in the context of varying degrees of vertical growth. When vertical growth occurs, as identified through SMTI analysis, it appears to be related to the activation of sub-vertical natural joints whereas for vertically confined stages the primary fracture set is subhorizontal suggesting delamination of fissile bedding planes is the dominant process. These differences, from stages in the same completion program, suggest that subtle background stress changes can result in very different behaviors. Full understanding of these mechanisms will lead to further optimization of these treatment programs to promote vertical growth to traverse structural barriers and retain containment of the treatment within zone.
Abstract In order to predict fracture propagation in naturally fractured reservoir, several fracturing models have been proposed. Especially, for analyzing interaction between hydraulic fracture and natural fracture, previous models have limits in representing fracture propagation, taking into account multiple planar fracture only with opening mode in fracture mechanics. When hydraulic fracture non-orthogonally encounters natural fracture, hydraulic fracture tip shears along natural fracture interface and then propagates into matrix once it meets the boundary of elastic region. Therefore, not only opening mode but sliding mode also needs to be considered in fracture propagation analysis. In this study, we proposed hydraulic fracture propagation model considering geomechanical factors as functions of Poisson's ratio and Young's modulus using multiple planar fracture with mixed mode by linearly superposing opening and sliding modes. The proposed model was used to analyze the fracture propagating behavior for different shales of Marcellus, Barnett, and Eagle Ford with respect to geomechanical properties. From the results of sensitivity analysis for Poisson's ratio, Young's modulus, and stress anisotropy on crossing angle of hydraulic fracture into natural fracture, it indicated that Young's modulus is mostly sensitive among geomechanical properties on fracture crossing angle. As Poisson's ratio and stress anisotropy increase, or as Young's modulus decreases, hydraulic fracture can easily penetrate into natural fracture. In the aspects of fracture mechanics, as Young's modulus increases, the implementation of sliding mode is more significant, whereas, almost no effect regardless of magnitude of Poisson’ ratio or stress anisotropy. Based on the results of sensitivity analysis, the proposed model was run for Marcellus, Barnett, and Eagle Ford shales having different geomechanical characteristics for examining the importance of sliding mode. From the results, since Poisson's ratio is low and Young's modulus is high in Barnett shale, the largest effect of sliding mode was yielded due to its highly brittle characteristics, in which this shale presents larger deformation in longitudinal direction than transverse. Meanwhile, in Marcellus shale, hydraulic fracture more easily crosses natural fracture with low value of crossing angle, because its Young's modulus is lower than Barnett shale, consequently, the implementation of sliding mode is less dominating. Furthermore, since Eagle Ford, representing higher Poisson's ratio and Young's modulus than Barnett shale, shows higher deformation in transverse direction by local stress change, the fracture crossing angle was estimated as higher value than Barnett shale. That is, hydraulic fracture is difficult to cross natural fracture, and thereafter, propagating direction of fracture is highly deviated. Therefore, particularly in Eagle Ford, the model with mixed mode was found to be extremely important on fracture propagating behaviors. As overall result, hydraulic fracture propagates diversely corresponding to shale characteristics as well as the existence of natural fracture, the stimulated reservoir volumes were estimated quite differently.
Lee, Dae Sung (Petroleum & Marine Research Department, Korea Institute of Geoscience & Mineral Resources) | Herman, Jonathan D. (Thayer School of Engineering, Dartmouth College) | Elsworth, Derek (Department of Energy and Mineral Engineering, Pennsylvania State University)
Abstract It is very difficult to predict the hydraulic fracture properties in shale gas reservoirs, such as Marcellus shale, because of the complex nature of hydraulic fracture growth, lack of good quality reservoir information, and very low matrix permeability. Furthermore, Marcellus shale is more sensitive to stress changes caused by hydraulic fracture shadowing and the net stress increase with production. The inclusion of the stress shadowing and the geomechanical factors provide a more realistic approach to predict the production performance of the horizontal wells with multiple hydraulic fracture stages in Marcellus Shale. The objective of this study is to investigate the impact of the stress shadowing on the hydraulic fracture properties in Marcellus Shale horizontal wells and consequently the production performance. The natural gas in the Marcellus Shale is produced most effectively by horizontal wells with multiple hydraulic fracture stages. The propagating fracture causes a stress change, commonly known as a stress shadow, in the vicinity of the fracture. The stress shadowing effects may result in a decrease in the width and conductivity of the subsequent fracture stages. In this study, a commercially available software which accounts for the stress shadowing was utilized to predict the hydraulic fracture properties based on the available information from a Marcellus Shale horizontal well. The available information included gamma ray (GR), density (RHOB), resistivity, and sonic (DTC & DTS) logs as well as the fracture stimulation treatment data. Treating pressures were calibrated by modifying the frictional parameters such as pipe friction and tortuosity factors. The predicted hydraulic fracture properties with stress shadowing effects as well as the Marcellus Shale properties were then utilized as the inputs for a reservoir simulation model in order to predict the production performance. Laboratory measurements and published studies on Marcellus shale core plugs provided the foundation for evaluating the impact of net stress on the matrix and fissure permeabilities as well as the relation between fracture conductivity and the net stress. The geomechanical factors were then incorporated in the production simulation model. Finally, parametric studies were performed to investigate the impact of fracture spacing on stress shadowing. The hydraulic fracture properties for different spacing were then incorporated in the production simulator to investigate their impact on the gas production. The inclusion of the stress shadowing and the geomechanical factors provided a closer agreement between the simulated and actual production history for the well under study. The stress shadowing effects were found to increase with closer fracture spacing. The fracture half-length, fracture height and especially, fracture width stress were impacted by stress shadowing. Additionally, it was observed that the stress shadowing impact is more significant in Marcellus shale due to low in-situ stress contrast with the adjacent zones. Furthermore, the stress shadowing effects were found to have more impact on the production than the location of the fracture stages. Finally, the stress shadowing can reduce gas recovery by as much as 20%.
Abstract One of today's challenges for shale reservoir developments is to increase the productivity per foot of drilled horizontal section while lowering the production cost to reduce the overall boe/$. Shale gas reservoirs are unconventional resources that need Multifractured Horizontal Wells (MFHW) to produce at commercial rates. Fracking methods have advanced dramatically in the last decade. Technologies are now capable of placing long MFHW with predefined fracs distance with large volumes of fluids injected causing intense formation fracturing. The final goal is to increase the well productivity per foot by increasing the size of the SRV (Stimulated Reservoir Volume) while reducing the cost of production. The objective of this paper is to study and compare the impact on recovery factor, productivity and well performance of different SRV geometries using a dual porosity dual permeability compositional model. This work examines three prolific US gas shale plays, Haynesville, Barnett and Marcellus, having different reservoir and fluid characteristics. Hydraulic fractures properties like half-length, width and density were studied alongside other reservoir properties (matrix and fracture permeability and porosity). These are considered amongst the key parameters influencing MFHW productivity and gas recovery. The chosen approach is a Cartesian grid to mimic the presence of large-scale permeable hydraulic fractures as main flow conduits and enhanced medium scale (equivalent to the grid size) natural fractures in MFHW that contribute to flow in stimulated areas. The method models matrix-fracture interactions, with property-selected refinement to simulate different SRVs geometries demonstrated by Whitson (2016) to be able to history match pressure behavior in shale gas reservoirs for the Haynesville and Marcellus. Numerical modeling of MFHW recovery factors, pressure and production profiles was done using a commercial simulator. Reservoir properties for analyzed shales were extracted from public data. Three different SRV models were studied to represent the enhanced medium scale fractures. The first model, matrix-hydraulic fractures system, is the simplest SRV modeled in this work, and is the base for a subsequent model obtained by adding an enhanced fracture stimulated SRV area around each large scale hydraulic fracture. The most complex SRV geometry modeled was created by adding an additional enhanced stimulated natural fracture area simulating the impact of hydraulic fractures in the medium scale natural fracture network (Whitson, 2016). Results show how relatively moderate increases in the enhanced stimulated SRV's volumes can have a large impact on cumulative gas production and recovery factor, demonstrating the importance of achieving successful large scale hydraulic fractures and/or stimulation of medium scale fractures between and around the major fractures. Changes in SRV geometry, caused by enhanced natural fractures due to hydraulic fracturing stimulation, demonstrated to also have a large impact on recovery factors. A sensitivity analysis was performed to study the impact that different reservoir properties including matrix permeability and fracking parameters (half-length and density) could have on cumulative production and recovery factor. Results can be used to help defining the best strategy to design hydraulic fracturing for different shale gas plays, optimizing the field development plan. This study can be extended to incorporate shale oil plays (Compositional models) and to investigate multiple wells interaction evaluating interferences between wells. This study provides a catalogue of typical cumulative production and pressure profile responses for three US shale gas plays with different characteristics and stimulation areas that can be used to aid practitioners in assessing the extent of the potential stimulated areas contacted by unit wells in modelled SRV's. In addition, sensitivity analysis provides information on key parameters to consider when estimating recovery factors ranges to use for estimating reserves and resources in shales with these characteristics.