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.
In this study we examine the ability of statistical models to simulate the magnitudes of seismic events induced by hydraulic fracturing (HF). The motivation for doing so is that, if operators are able to forecast potential event magnitudes, then they may be able to discriminate at an early stage between the normal case, where HF does not induce large, felt seismic events, and the abnormal case, where larger events do occur. By doing so, an operator may be able to take mitigating actions for the abnormal cases in order to avoid induced seismicity. Here we examine two statistical models for induced seismic event magnitudes, and apply them to two case studies consisting of microseismic datasets collected during hydraulic fracturing in the Horn River Shale. At both sites, some stages showed evidence for fault reactivation and larger induced seismic events (MMAX > 1.0). We find that these statistical models are capable of identifying the fault-reactivation stages relatively early on, and provide reasonably accurate forecasts of the eventual largest events. Had such modelling been performed in real time, it could have formed the basis for a strategy to mitigate induced seismicity.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 208A (Anaheim Convention Center)
Presentation Type: Oral
Next to the Alaska Highway 97 north of Fort St. John in the thick forests of northern British Columbia natural gas is trucked out from the Highway Natural Gas Liquids Plant in the North Montney shale formation. Unconventional oil and gas have come to dominate the exploration and development scene in Western Canada since 2005, much as they have in the US. Both countries share essential elements needed to launch and sustain unconventionals: A long history of drilling, publicly available data, well-understood sedimentary basins, extensive infrastructure, a diverse corporate sector, and regulatory regimes supportive of innovative resource development. Following closely on developments in the US, the “tight gas” concept was a key component of the Canadian oil patch in the 1980s and 1990s. Horizontal drilling and hydraulic fracturing were employed in ever-tighter reservoirs, and in the early 2000s, Canadian operators began to appreciate the true potential of oil and gas from shales, tight reservoirs, and coal seams.
However, successful hydraulic stimulation treatments can be challenging to implement, and require considerable forethought. Compositional variation, rock fabric, geomechanical stratigraphy, and natural fracture systems all interact to influence and complicate hydraulic fracture treatments in shale reservoirs (Gale et al., 2006; Passey et al., 2010). Previously published work has highlighted the interaction between natural and induced fractures in the Horn River Basin (Dunphy and Campagna, 2011). This indicates that effective well completions require the efficient utilization of natural fracture systems to enhance permeability and drainage volume. Since natural fracture systems are a significant factor controlling the response of shale reservoirs to hydraulic fracturing, it is essential to identify and understand the key parameters of natural fracture networks that influence the effectiveness of hydraulic fracturing treatments. This paper combines results from natural fracture network characterization with discrete fracture network (DFN) modelling to identify the key parameters that influence hydraulic fracture geometry in the Horn River Basin.
Sheng Yang, University of Calgary; Nicholas B. Harris and Tian Dong, University of Alberta; and Wei Wu and Zhangxin Chen, University of Calgary Summary This paper documents the formation of natural fractures in the Horn River Group, a major Canadian shale gas play, and addresses relationships between natural-fracture development and rock-mechanical properties derived from cores and well logs. Most natural fractures in the Horn River Shale are narrow vertical fractures, sealed with carbonate minerals. In this study, the formation of observed fractures is primarily determined by a lithology type, mineral composition, and rock-mechanical properties at the timing of fracturing. Brittleness is an important geomechanical property controlling the formation of fractures, because brittle shale is more easily fractured than ductile shale, and fractures in brittle shale tend to persist when the fracturing pressure is released. In this study, a hardness value measured by a commercial hardness tester is found to be a good proxy for the brittleness of shale layers. On the basis of a statistical analysis, the threshold values of both hardness and brittleness are estimated to predict the distribution of natural fractures, assuming that the mechanical properties of the host rock were relatively stable from at least the time at which fractures formed. Hardness values are shown to be more reliable than brittleness. Introduction Researchers have conducted many studies on different aspects of natural fractures and fractured reservoirs (Lorenz et al. 1991; Laubach et al. 2004) [e.g., the characterization and effects of fractures in the carbonate and siliciclastic reservoirs of the Middle East (Ameen et al. 2009, 2010, 2014)]. In recent years, natural fractures in shale reservoirs have become a key focus of research (Curtis 2002; Kresse et al. 2011; Gale et al. 2014) [e.g., the comprehensive study of natural fractures in the Qusaiba shale conducted to evaluate shale reservoir proceptivity by Ameen (2016)].
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.
Ueda, Kenji (INPEX Corporation) | Kuroda, Shintaro (INPEX Corporation) | Rodriguez-Herrera, Adrian (Schlumberger) | Garcia-Teijeiro, Xavier (Schlumberger) | Bearinger, Doug (Nexen Energy ULC) | Virues, Claudio J. J. (Nexen Energy ULC) | Tokunaga, Hiroyuki (INPEX Corporation) | Makimura, Dai (Schlumberger) | Lehmann, Jurgen (Nexen Energy ULC) | Petr, Christopher (Nexen Energy ULC) | Tsusaka, Kimikazu (INPEX Corporation) | Shimamoto, Tatsuo (INPEX Corporation)
A design of hydraulic fracturing in variably-stressed zones is one of key components for an effective multi-zone, multi-horizontal well pad treatment. In the recent literature, optimum completion strategies catering for stimulation-induced in-situ stress changes are discussed, however, only few of these focus on vertical stress changes and its impact on multi-zone fracture geometries. In this paper, we present an approach to design contained hydraulic fractures in a high stress layers by studying the role of vertical stress shadowing on actual field data.
In modeling hydraulic fractures with pseudo-3D models, if fracture simulations are initiated in high stress zones, "artificially" unbounded height growth results in very limited lateral propagation. On the other hand, 3D hydraulic fracturing models are too computationally expensive to optimize large design jobs, for example, in multi-horizontal well pads. In this paper, we employ a Stacked Height Growth Model, whereby fractures are also discretized vertically yet retain the numerical formulation pseudo-3D models. Coupling with finite element stress solvers then allows to identify vertical stress changes in the vicinity of induced hydraulic fractures and to understand the interference between hydraulic fracture sequences and their respective microseismic signatures.
Considering a potential combination of fracturing sequences, it was revealed that stress perturbations from the neighboring well hydraulic fractures initiating from low stress layers can be used to increase stress within the same zone and also potentially reduce stresses in higher-stress layers above and below. By modeling and calibrating an actual multi-zone, multi-horizontal stimulation job, we elaborate on the benefits of increasing stress barriers before fracturing in higher-stress layer to avoid the chances of re-fracturing from high stress zones. Regarding hydraulic fracture geometries, we explain our results by analyzing actual microseismic observations with respect to simulated stress patterns after stimulation. We explore the notion of deliberately ordering hydraulic fracture to manage vertical interference and create more contained fractures in a multi-zone horizontal well pad.
Fracturing in a higher-stress zone will naturally divert the energy into low stress, potentially unproductive zones. In an effort to manage this phenomenon, this paper presents one of the few data-rich case studies on multi-zone, multi-well engineered stimulation design. The approach shown in this paper can be a helpful reference to understand fracture height growth in the presence of both vertical and horizontal stress shadowing.
We present a case study of hydraulic fracturing treatments for two horizontal wells located in the Horn River Basin, B.C. The wells were completed using a technique that we refer to as Short Interval Re-injection (SIR). For each individual treatment stage, this technique makes use of an initial injection interval using conventional hydraulic fracturing pumping procedures, followed by a “soaking" period that may last from a few hours to about one day in duration, during which the well is temporary shut in. This is followed by a subsequent re-injection interval with a pumping schedule similar to the first interval. Several commercial names are in use to describe this type of approach, which has a desired goal of enhancing the overall effectiveness of the treatment. In this study, we observe a significant increase in the rate of microseismic activity that occurs after the initial soaking period. This type of response has been documented previously and, in some cases, has been empirically related to increased production for wells. We postulate that cohesion of pre-existing fractures is reduced by the initial injection and soaking period, facilitating reactivation of fractures during the second injection. A numerical model has been developed using the software 3DEC in which the cohesion parameter for a discrete fracture network (DFN) is set to zero after the first injection stage. Preliminary results produce a satisfactory match with respect to increased events. Future work will include adjustments to the DFN in order to increase the match with the spatial locations.
The Horn River Basin (HRB) is an important resource play in northeastern British Columbia, Canada. While conventional oil and gas developments have been underway in the HRB for several decades, since 2005 operators have targeted the large shale resources that are in place.
A hybrid hydraulic fracture (HHF) model composed of (1) complex discrete fracture networks (DFN) 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 considering the initial hydraulic fracturing efficiency, fracture network complexity, mechanics, and microseismicity distribution along 145 stimulated stages in a multilateral horizontal well on the Muskwa, Otter Park and Evie Formations in the Horn River Shale in Canada.
Hydraulic fracturing jobs in shale reservoirs are designed with a view to achieve economic production by exploiting fracture network complexity. The task involves significant challenges in modeling and forecasting, which complicates the examination of operations to enhance their performance, including refracturing or infill drilling.
In this study, an HHF is run in a numerical simulation model to evaluate the SRV performance in planar and complex fracture networks using microseismicity data collected during 75 stages of hydraulic fracturing in the Horn River shale. Post-fracturing production is appraised with Rate Transient Analysis (RTA) for determining effective permeability under flowing conditions, compare to the numerical simulation and the hydraulic fracturing design.
Fracturing stages with larger fracture patch sizes, associated with the microseismic events in a fixed stress drop, correspond to higher stimulated areas, fracture conductivity, and gas production. Several microseismic events are observed in the heel of the laterals that are aligned to the far field NE stresses, indicated a loss of efficiency along the wellbore lateral during hydraulic fracturing. The hydraulic propagation modeling revealed increment of the leak-off coefficient, related to the natural fractures and communication with other stages. The production performance is evaluated in the numerical model, to measure interference between stages.
The SRV, modeled with HHF networks, is able to match the post-fracturing production history. Fracture mechanics is important in order to understand the flowing performance of the reservoir.
The inclusion of propagating models and RTA allowed to characterize possible fracture geometries in the reservoir and to observe limitations inherent to large dispersion and uncertainty of the microseismicity cloud. Also, to observe areas where the stimulation may have propped natural fractures totally or partially, which will benefit the production of gas.
This study presents a better understanding and characterization of the SRV in shale gas reservoirs, especially in those cases where microseismicity dispersion is problematic and where the SRV is not easily delimited.
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.