Shale Gas Modeling Workflow: From Microseismic to Simulation -- A Horn River Case Study
- Alex Novlesky (Computer Modelling Group Ltd) | Anjani Kumar (Computer Modelling Group Inc) | Stefan Merkle (Nexen Inc.)
- Document ID
- Society of Petroleum Engineers
- Canadian Unconventional Resources Conference, 15-17 November, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 5.5.8 History Matching, 5.1.1 Exploration, Development, Structural Geology, 5.5 Reservoir Simulation, 2.5.4 Multistage Fracturing, 5.3.9 Steam Assisted Gravity Drainage, 2.5.2 Fracturing Materials (Fluids, Proppant), 2 Well Completion, 5.6.5 Tracers, 5.1.5 Geologic Modeling, 5.8.2 Shale Gas, 4.1.2 Separation and Treating, 2.2.2 Perforating, 1.6 Drilling Operations, 4.3.4 Scale, 3 Production and Well Operations, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.4.3 Sand/Solids Control
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Recent success of commercial shale gas developments in a number of basins throughout North America can be attributed to the application of advanced technologies used to drill horizontal wellbores, stimulate the shale reservoir, and optimize productivity of shale-bearing formations. Many of the drilling and completion techniques learned from the thousands of wells drilled and stimulated in more mature shale basins, such as the Barnett, have been applied to newer shale discoveries such as the Marcellus and Haynesville in the United States, and both the Montney and the remarkable Horn River Basin in Canada. The unique properties of each shale, however, preclude a "cookie-cutter?? development approach from being applied. Each play must be optimized as a unique reservoir.
In order to utilize numerical simulation as a tool in optimizing well design, one needs to develop a model that appropriately represents the complex process of gas flow from the native reservoir to the hydraulic fractures and subsequently to the wellbore. This is challenging due to poor understanding of variables such as pressure dependent permeability variation, fluid cleanup, relative permeability effects, non-Darcy flow, methane desorption in a nano-Darcy shale matrix, and fracture conductivity variations from the dominant hydraulic fractures to the secondary induced and natural fractures. Another challenge is accurate representation of the hydraulic fracture. Is the fracture planar or complex? What is the fracture geometry? What is the fracture intensity within the stimulated volume? What is effectively propped? What is the proppant distribution within the fracture system? How does this tie to effective conductivity and does it vary with distance from the wellbore (three dimensionally)?
Finding a unique match to historical production is very challenging. Shale gas operators collect a large amount of data including cores and logs (specialized for nano-Darcy rock), micro seismic, diagnostic fracture injection testing (DFIT), fluid and proppant tracers and more. This data is used to better characterize the reservoir and the natural and hydraulic fractures and can help to constrain model inputs.
This paper discusses a workflow used in developing a numerical shale gas model for Nexen's Horn River shale gas reservoir. Presented is a practical and systematic approach to using surveillance data; specifically microseismic data in construction of the stimulated reservoir volume (SRV) and the network of hydraulic fractures in the model. Discussions will also focus on accurately modeling complexities such as non-Darcy flow in the hydraulic fractures, pressure-permeability dependencies, variations in hydraulic fracture conductivity and fluid cleanup. The objective is to gain understanding and insight into the uncertainties that have the greatest impact on well performance.
Shale gas resources are typically developed most efficiently using horizontal well and hydraulic fracturing technology. Most shale resource plays are currently being developed with horizontal wells that have multiple large volume transverse slick water fracture stimulations. Ultimately, the horizontal well productivity is heavily tied to the effectiveness of the fracture stimulation and the ability to generate a large degree of fracture surface area that will maximize matrix rock/shale contact and connection to the wellbore.
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