The Ultimate Potential for Unconventional Gas in the Horn River Basin: Integrating Geological Mapping with Monte Carlo Simulations

Abstract

The Horn River Basin of northeastern British Columbia, Canada, contains natural gas in three Devonian shale units. Isopachs, depths, and net-to gross-pay ratios were determined from well logs for the Muskwa, Otter Park, and Evie Shales and then gridded. Pressure gradients were determined from well test and production data and then gridded into a single grid shared between shales. Because grid points were shared between each grid, volumetric and adsorbed gas equations could be integrated into each grid point. Static values or distributions could then be applied to equation variables and Monte Carlo simulations run to determine probabilistic gas in place (GIP) and marketable resources for each grid point, which were then summed for each shale.Grid points for the isopach and depth maps were treated as static values in the equations while net-togross and pressure gradient grid points became most likely values in Beta distributions where end points were assigned using regional low and high values. Most non-mapped variables in the equations were filled with Beta distributions based on typical values in the area and then applied across the basin without any local variations. On each distribution, whether based on mapped or unmapped variables, a second, overlying distribution was applied on a basin scale. This made entire iterations run a full range from pessimistic to optimistic. A few non-mapped variables in the equations were given static values.Recoverable gas resources were estimated by applying a recovery factor to free GIP estimates. Recoverable volumes from adsorbed GIP estimates were determined from a recovery factor applied to the portion of gas that would desorb during production as pressure decreased to the assumed well abandonment pressure. To determine marketable gas, gas impurities and fuel gas that would be used for processing and transport were estimated and subtracted from the recoverable estimates. Further, certain lower quality areas of the basin were excluded from the assessment, based on a low likelihood of being developed.

Hydraulic Fracturing‐Induced Seismicity

“…The Horn River Basin hosts the Middle‐Late Devonian Horn River Group, composed of three organic‐rich shale units (Evie, Otter Park, and Muskwa Formations) with a net thickness >300 m (British Columbia Oil and Gas Commission, BC OGC, 2012). With an estimated marketable dry gas resource of more than 70 trillion cubic feet (2.0 × 10 12 m 3 ) (Johnson et al, 2011), the Horn River Basin represents one of the largest shale gas plays in North America. Industry operations to assess and develop the shale gas resources within the Horn River Basin commenced in November 2006 and peaked in 2011 but have since been suspended, largely due to the low North American prices for dry gas and the great distance of the Horn River Basin from markets.…”

Stimulated Shale Volume Characterization: Multiwell Case Study from the Horn River Shale: II. Flow Perspective

“…and (Johnson et al 2011) have described the Horn River Basin (HRB) and estimate the gas in place at approximately 500 TCF. Johnson et al estimate that 78 TCF will be ultimately recovered.…”

Petrophysical approach for estimating porosity, clay volume, and water saturation in gas-bearing shale: A case study from the Horn River Basin, Canada

“…From the youngest to the oldest, these three formations are known as Muskawa, Otterpark and Evie; they are the siliciclastic deeper-water age-equivalents to the shallow water Leduc, Swanshill and Slavepoint carbonate formations, respectively. The shaly Fort Simpson formation overlays the Muskawa formation; the Keg River carbonate formation, which serves as a fracture barrier, underlays the Evie formation (Johnson et al 2011) (Figure 2). Characteristics of each shale layer are relatively similar, although thickness varies depending on the location.…”