A hybrid-hydraulic-fracture (HHF) model composed of (1) complex discrete fracture networks (DFNs) and (2) planar fractures is proposed for modeling the stimulated reservoir volume (SRV). Modeling the SRV is complex and requires a synergetic approach between geophysics, petrophysics, and reservoir engineering. The objective of this paper is to characterize and evaluate the SRV in nine horizontal multilaterals covering the Muskwa, Otter Park, and Evie Formations in the Horn River Shale in Canada, with a view to match their production histories and to evaluate the effectiveness and potential problems of the multistage hydraulic-fracturing jobs performed in the nine laterals.
To accomplish this goal, the HHF model is run in a numerical-simulation model to evaluate the SRV performance in planar and complex fracture networks using good-quality microseismicity data collected during 75 stages of hydraulic fracturing (out of 145 stages performed in nine laterals). The fracture-network geometry for each hydraulic-fracture (HF) stage is developed on the basis of microseismicity observations and the limits obtained in the fracture-propagation modeling. Post-fracturing production is appraised with rate-transient analysis (RTA) for determining effective permeability under flowing conditions. Results are compared with the HHF simulation and the hydraulic-fracturing design.
The HHF modeling of the SRV leads to a good match of the post-fracturing production history. The HHF simulation indicates interference between stages. The vertical connectivity in the reservoir is larger than the horizontal connectivity. This is interpreted to be the result of the large height achieved by HFs, and the absence of barriers between the formations.
It is concluded that the HHF model is a valuable tool for evaluating hydraulic-fracturing jobs and the SRV in shales of the Horn River Basin in Canada. Because of the generality of the Horn River application, the same approach might have application in other shale gas reservoirs around the world.
We analyzed microseismic spatial and temporal distribution, magnitudes, b-values, and treatment data to interpret and explain the observed anomalies in microseismic events recorded during exploitation of shale gas reservoirs in the Horn River Basin of Canada. The b-value shows the relationship between the number of seismic events in a certain area and their magnitudes in a semilogarithmic scale. The b-value is important because small changes in b-value represent large changes in the predicted number of seismic events. In this study, b-value is considered as an indicator of the mechanism of observed microseismicity during hydraulic-fracturing treatments.
We estimated the directional diffusivity to define the microseismicity front curve for each stage of hydraulic fracturing. On the basis of our definition of an average front curve, we managed to separate most of the microseismic events that are related to natural-fracture activation from hydraulic-fracturing microseismic events. We analyzed b-values for microseismic events of each stage before and after separating fracture-activation microseismic events from original data, and created a map of b-values in the study area. This allowed us to approximately locate activated fractures mostly in the northeastern part of the study wellpad. The b-value map agrees with our assumption of activated-fracture locations and high ratio of seismic activities. The dominant direction of the suggested activated natural fractures agrees with the general trend of the Trout Lake fault zone located approximately 20 km west of the study area.
Suggested fracture direction also agrees with anomalous-events density, energy distribution, and treatment data. We are proposing intermediate b-values for calculation of the stimulated reservoir volume (SRV) in areas with both hydraulically fractured events and events related to natural-fracture-network activation in those instances in which it is not viable to separate events based on their origin.
Yousefzadeh, Abdolnaser (Schulich School of Engineering, University of Calgary) | Li, Qi (Schulich School of Engineering, University of Calgary) | Virues, Claudio (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
We present a comparison of three different hydraulic fracture models as well as an anisotropic diffusivity model with the observed microseismic data from shale gas reservoirs in the Horn River Basin of Canada. We investigated the validity of these models in the prediction of hydraulic fracture geometries using tempo-spatial extension of microseismic data. In the study area, ten horizontal wells were drilled and hydraulically fractured in multiple stages in the Muskwa, Otter Park, and Evie shale gas formations in 2013. The treatments were monitored by downhole microseismic measurements.
We integrated microseismic analyses, geomechanical information extracted from well logs, and fracturing treatment parameters performed in the area. We compared fracture geometry predicted by Perkins-Kern-Nordgren (PKN), Khristianovic-Geertsma-de Klerk (KGD), and a Pseudo-3D (P3D) fracturing models as well as an anisotropic diffusivity model with actual fracture geometries derived from microseismic records in more than one hundred fracturing stages.
For the study area, we find that there are no barriers to hydraulic fracture vertical growth between the Muskwa, Otter Park and Evie shales. Therefore, the fracture height to length ratio is higher than unity in many stages. Large fracturing heights suggest that the PKN model might be more suitable for fracture modeling than the KGD model. However, our analyses show that the fracture length predicted by the KGD model is closer to, but still far less than the fracture length illustrated by microseismic events. Pseudo 3D model also predicts fracture lengths which are slightly larger than the modeled fracture lengths by the KGD and PKN equations and still significantly smaller than the microseismic fracture lengths.
These differences are observed throughout all stages suggesting that these methods are not able to perfectly predict the hydraulic fracturing behavior in the study wellpad. Vertical extension of microseismic data with linear patterns into the Keg River formation below the shale formations suggests the presence of natural fractures in the study area.
This study presents a distinctive insight into the complex hydraulic fracture modeling of shales in the Horn River basin and suggests that diffusivity mapping is a simple, but powerful tool for hydraulic fracture modeling in these formations. Observed microseismic fracture lengths are significantly higher than lengths predicted by the geomechanical models and closer to diffusivity models, which suggests the possibility of increasing well-spacing in future development using diffusivity equation for improving treatment design.
We present an integrated interpretation of microseismic, treatment, and production data from hydraulic fracturing jobs carried out in two adjacent wellpads in the Horn River Basin, Northeast British Columbia, Canada. Wellpad I includes 8 wells which were drilled and fractured in the Muskwa and Otter Park formations (4 wells in each formation) in 2010. Wellpad II includes 3 wells drilled and fractured in each of the three shale formations, Muskwa, Otter Park, and Evie, in 2011. There is one-year interval between fracturing of the first and second wellpads.
We studied magnitudes, b-values, moment tensor inversion, and the spatial and temporal distribution of three-component microseismic events recorded during more than 200 stages of fracturing by multi-well downhole-arrays. We analyzed Gutenberg-Richter frequency-magnitude graphs for each fracturing stage, and with proper integration of b-values, fracture complexity index (FCI), moment tensor inversion information, and treatment data, we distinguished hydraulic fracturing-related events and events associated with slip along the surface of natural fractures. The results are compared with five-year gas production data in each well.
Our results show the effects of natural fracture network on well-connectivity as well as spatial distribution of microseismic data. We show that hydraulic fracturing and production from wellpad II lead to interference with wells already producing from wellpad I. The integrated study indicates that hydraulic fracturing and production from wellpad II is the main source of four months of anomalous production decline in wellpad I. This anomalous production decline started about two months after hydraulic fracturing in wellpad II. We also show that the tendency of microseismic distribution in wellpad II toward wellpad I is due to the connection of the two wellpads through a network of pre-existing natural fractures, which are approximately parallel to the largest principal compressive stress in the area.
Both identification of natural fractures and information about interactions between hydraulically fractured wells are essential for optimum well placement and completion, reservoir characterization, stimulated reservoir volume calculation, and reservoir simulation. This study presents a distinctive insight into integrated interpretation of microseismic events and production data to identify the activation of natural fractures and interference between the hydraulically fractured wells.
Yousefzadeh, Abdolnaser (Schulich School of Engineering, University of Calgary) | Li, Qi (Schulich School of Engineering, University of Calgary) | Virues, Claudio (CNOOC- Nexen) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
We analyzed microseismic spatial and temporal distribution, magnitudes,
We estimated the directional diffusivity to define the microseismicity front curve for each stage of hydraulic fracturing. Based on our definition of front curves, we managed to separate most of the microseismic events data that are related to natural fracture activation from hydraulic fracturing events. We analyzed the
Suggested fracture locations agree with anomalous events' density, energy distribution and treatment data. We are defining and proposing intermediate
Different acquisition geometries of the baseline and monitor seismic surveys produce different patterns of acquisition footprints. The resulting time lapse image shows the differences in artifacts, which may dominate the changes in the reflectivity model due to the production from or injection into the reservoirs. Synthetic data is used to show how different acquisition geometries between baseline and monitor surveys lead to different Kirchhoff migration artifacts for the same reflectivity model.
The least squares prestack Kirchhoff migration (LSPSM) is performed separately on the baseline and monitor data to attenuate these effects and provide comparable high resolution images for both pre- and poststack time lapse studies. A joint least squares Kirchhoff prestack migration (LSPSM) of both baseline and monitor data is introduced which attenuates the migration artifacts and returns high resolution LSPSM and/or time lapse images.
Summery Kirchhoff least squares prestack migration (LSPSM) attenuates acquisition artifacts resulted from the irregularities or sparseness in the seismic data sampling and improves the image resolution. This study shows that this improvement needs an accurate subsurface velocity information. It is shown that the improvement in the resolution of the resulted LSPSM, convergence rate of the least squares conjugate gradient (LSCG) iterations, and the ability of a good data reconstruction by LSPSM are the three factors that strongly depend on the accuracy of the background velocity and can be used as effective tools for ensuring the accuracy of the velocity model. Introduction Because of its many advantages, Kirchhoff remained one of the main practical choices for seismic migration. Its ability to handling incomplete and irregular seismic data is probably the main advantage over the other migration methods.