Gas Resources – WCSB and East Coast

This figure shows the gas resource potential of Western Canada and the East Coast.

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Gas Basin Outlook, Bcf/d

This figure shows dry-gas production for major US gas basins to 2025. The blue areas represent production from gas wells drilled before 2017; the hatched blue is Solomon‘s forecast of production.

  • In 2017, US natural gas production growth and development was primarily focused in three basins: Marcellus, Utica, and Haynesville.
  • The increased maturity of tight-gas plays is forecast to continue in the Rockies and in the Mid Continent & Permian. Production from these plays will decline over the forecast period.
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North American Natural Gas Resource Cost, USD/Mcf

This figure illustrates Solomon’s view of the distribution of North American ultimate potential natural gas resources subdivided by region and by break-even gas price. The size of the pie area corresponds with the regions’ ultimate natural gas resource potential. Ultimate potential resource is the amount of resource that is thought to be technically recoverable, without regard to the economics of extraction.

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Regional Dry Gas Production Forecast, Bcf/d

This figure shows historical dry-gas production from 2005 to 2017 (blue bars), and each key region’s anticipated production forecast to 2025 (red bars). Only major basins and plays within the major producing regions are presented and summarized.

  • North American gas-production growth is driven by increased demand. Low-cost plays attract investment capital and grow, whereas investment in higher-cost plays stagnates and production declines accordingly.
  • The largest production growth is expected in Appalachia (Marcellus and Utica), with significant growth from 2017 to 2025, followed by Western Canada. Other regions will have declining production.
  • Full-cycle cost of gas includes drilling and completion, land and seismic costs, operating cost, overhead, basis differential, taxes and royalties, producer return, and NGL price uplift.
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North American Production Growth, Dry Gas, Bcf/d

This figure shows dry-gas production change for 2005 to 2016 and 2017 to 2025. Green represents low full-cycle cost, yellow represents average full-cycle cost, and red represents high cost.

  • The largest production growth is expected in Marcellus and Utica (Appalachian Basin).
  • WCSB grows in response to gas demand for LNG exports after 2022.
  • All growth areas are associated with lower full-cycle cost, which includes NGL price uplift.
  • Although Green River and Barnett have average full-cycle cost, these basins will not experience growth due to maturity of the plays.
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Estimated Ultimate Recovery, Raw Gas Bcf/well

This figure shows Estimated Ultimate Recovery (EUR, measured in Bcf per well) for major North American Gas Basins in 2010, 2017, and 2025.

  • Western Canada Conventional EUR on an average basis is very low, which makes the unit cost of adding reserves very high.
  • The bright spot in Western Canada is the Montney tight-gas play in the NGL-rich part of the play.
  • Appalachian EUR includes the Marcellus Shale; East Texas, North Louisiana EUR includes the Haynesville Shale; GoM Coast EUR includes the Eagle Ford Shale. 
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Marcellus Production & Connections

This figure presents gas production and well connections by play to 2025. The solid blue areas represent production from wells drilled before 2017; hatched blue is production from new wells. Red bars are well connections. Utica liquids-rich gas production from Eastern Ohio and South West Pennsylvania (SW PA) is forecast to grow substantially. Utica Pennsylvania North gas production is currently limited, but expected to start growing after 2020. Utica connections will almost triple during the forecast period. Most drilling in Marcellus SW PA is conducted in liquids-rich areas. Marcellus North East Pennsylvania (NE PA) produces dry gas, which does not require processing.

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Western Canadian Natural Gas Production

Western Canadian Natural Gas Production is expected to remain flat until at least 2021, when LNG exports start to grow. Western Canadian conventional and CBM production will decline while Tight and Shale Gas production will reach over 80% of total production.

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Montney Tight Gas Production Outlook, Bcf/d

This figure shows the Montney gas forecast categorized by productivity and associated resource distribution. Montney tight-gas production will continue to grow, expanding after 2020 when gas supply will supplement LNG exports. By 2025, Montney gas production is expected to more than double compared to 2015.

  • Montney AB and BC rich-gas areas will provide the majority of Montney gas production growth in the forecast period. In conjunction with higher initial productivity, these areas provide the most attractive well economics.
  • The Alberta rich forecast is flatter than the BC Montney areas, due to more limited higher productive sweet-spot areas. Both the Alberta rich and BC North Montney forecasts will more than double by 2025.
  • Development of Montney dry gas will be very limited due to poor economics resulting from low NGL yields.
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North American Dry Gas Supply Outlook to 2025

This chart illustrates the continued growth of dry-gas production in North America since 2005. Average initial gas well productivity in these growth basins will increase due to a strong focus on sweet-spot drilling and technology improvements. North American gas rig count doubled in 2017. US Lower 48 associated gas production will remain flat at around 10 billion cubic feet per day (Bcf/d).

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Marcellus Initial Productivity, MMcf/d

This figure presents new well IP by play to 2025. NE PA average IPs are one of the highest in continental US. Marcellus West Virginia (WV) IPs will remain flat.

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Utica Shale Gas-Condensate

This figure presents gas production and well connections by play to 2025. Solid blue areas represent production from wells drilled before 2017; hatched blue areas represent production from new wells.

Utica liquids-rich gas production from Eastern Ohio and South West Pennsylvania is forecast to increase threefold from that of 2017. Utica Pennsylvania North gas production is currently limited, but after 2020, production will start to undergo growth. Utica connections will almost triple during the forecast period.

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Rockies & Permian Dry Gas Production, Bcf/d

This figure presents Rockies and Permian gas production by basin to 2025. Due to play maturity and higher cost compared to other regions, the Rockies region overall will exhibit declining production out to 2025.

  • Green River will grow slightly during the forecast period. Currently, major operators in Green River include Questar Energy, Ultra Petroleum, and Johan Energy.
  • Almost no drilling is expected in San Juan, Power River, and Uinta during the forecast period since these basins have the highest Rockies cost.
  • Green River had the highest 2017 production, followed by San Juan and Piceance.
  • The Permian is predominantly an oil basin.
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Rockies & Permian Average Gas Wells IP, MMcf/d per well

This figure presents Rockies and Permian initial productivities (IPs) to 2025.

  • The Permian is predominantly an oil basin. Permian IP drops to 30% from its peak in 2015. This growth is related to increased gas well drilling with a higher liquid content. These wells usually have lower gas IP in comparison to wet and dry gas wells.
  • Green River has the highest IP among all basins in the Rockies and will grow slightly during the forecast period.
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Rockies and Permian Gas Connections, M well/yr

This figure presents Rockies and Permian gas connections to 2025. The Permian is predominantly an oil basin. The number of new gas-well connections in the Permian is expected to almost double in 2017 compared to 2015. This growth is related to increased gas well drilling with a higher liquid content. The number of connections in Green River and Piceance is expected to be flat.

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Gulf of Mexico Deep Gas

This figure shows a schematic cross-section of the Ultra-Deep play and a map showing its relation to the Deepwater plays.

  • The Deep Shelf lies more than 15,000 feet below the outer continental shelf, in water depths ranging to 1,000 feet.
  • Much of the Deep Shelf could access existing Shelf infrastructure, saving development costs.
  • The region is mature with today’s technology—3D seismic has been very successful in delineating shallower prospects, and production has declined since 2002.
  • Potential remains for the pre-Miocene (productive onshore and in Deepwater) of the Ultra Deep Shelf (20,000 to 30,000+ feet), as demonstrated by McMoRan’s Davy Jones discovery.
  • Advanced drilling technology is needed for these high-pressure, high-temperature Ultra Deep wells, which can cost over 100MM USD.
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Relative Shale Play Size – IP Distribution Maps

This figure shows the relative areal extent of key US shale plays; the Utica is a little smaller than the Marcellus. Note: The maps are sized to the same distance scale.

  • Maps show initial productivities (IPs) used in Solomon’s production forecasting.
  • The highest gas well productivity is shown in red, the lowest in dark blue.
  • Wells are ranked based on their IPs; polygons with different ranges of initial productivity are generated; and the area of each polygon is calculated.
  • Well density is calculated for each basin and each range of IP.
  • Well connection forecasts are constrained by well density and maximum number for each range of IP.
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Western Canadian Gas Well Connections

This chart shows the Western Canadian Gas Well Connections well connection forecast to 2025. The number of well connections will increase modestly over the forecast period. The number of well connections dropped 40% in 2016 from 2015 due to continued downward pressure on oil and gas prices and the resulting constraint of industry cash flow. Horizontal wells account for 90% of well connections. Connections will increase slightly in 2017. Number of connections will remain in a narrow band through 2018–2023 due to flat demand for Western Canada gas supply. Connections will slightly increase after 2023 to meet LNG export demand. With a continued increase in new gas well productivity from horizontal drilling in the western portion of the basin, fewer gas connections will be required to replace gas production lost to decline and provide for production growth.

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Western Canada New Gas Well Productivity

This chart shows the New Gas Well Initial Productivity forecast to 2025. Initial Productivity will increase to 5.4 MMcf/d in 2025 from 3.8 MMcf/d in 2016.

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Montney Lease Condensate Yield, bbl/MMcf

This figure illustrates the hydrocarbon distribution in the Montney play ranging from dry gas (blue) to the southwest and oil (olive green) to the northeast. The figure also identifies the three core areas—BC North, BC South, and Alberta—which are further subdivided based on the hydrocarbon type.

  • Condensate: over 80 bbl/MMcf
  • Rich: 25–80 bbl/MMcf
  • Wet: 10–25 bbl/MMcf
  • Dry: less than 10 bbl/MMcf
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CBM Production Outlook

  • Since 2002, Horseshoe Canyon coalbed methane (CBM) has moved from pilot projects through commercial development to maturity.
  • Horseshoe Canyon coals are dry—only small amounts of water are produced.
  • CBM is high-cost relative to other opportunities in Western Canada and North America and production is declining.
  • Horseshoe Canyon gas-in-place resource is estimated to be 66 Tcf, though most of it is uneconomic.
  • Mannville CBM was a pilot that failed to deliver commercially. Mannville coals are typically deeper and commonly wet, requiring costly water handling and disposal (re-injection back into deep disposal wells).
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Tight Gas Plays

Tight gas is not defined in Canada; Solomon defines it as:

  • Laterally continuous, generally thick sands, conglomerates, and carbonates with low matrix permeability.
  • Saturated with sweet gas and often liquids rich.
  • Includes Greater Sierra (Jean-Marie) and the extended Deep Basin.
  • Excludes Eastern shallow gas and the Foothills.
  • Consistent need for large fracture stimulation to connect pore space to the well bore.
  • Jean-Marie peaked at 520 MMcf/d in 2004; wells commonly horizontal and underbalanced.

Extended Deep Basin

  • A thick section of Mesozoic low-permeability sands and conglomerates.
  • Economics are improved by natural gas liquids (NGLs), using existing infrastructure, and commingling production.
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How Unconventional Gas is Different

It’s “Engineered” or “Manufactured” with New Technologies
  • The two key technology advances for unconventional gas (and oil) are horizontal drilling and fracturing.
  • Horizontal wells rapidly became the majority of gas wells drilled. The well is drilled vertically, but then, at the producing zone, the drill bit is steered until the well bore is horizontal. Drilling continues horizontally until the end of the well is reached. The horizontal section can be up to 5,000 ft long, and a number of horizontal sections may be drilled from the same vertical well.
  • Horizontal wells increase the reservoir volume, which is in contact with the well so the well will produce at higher rates. Though horizontal wells cost more to drill than vertical ones, the higher cost is usually more than offset by the higher production. Pad drilling—multiple wells drilled from a single surface location—reduces the environmental footprint and costs.
  • The figure presents a horizontal well schematic and the multi-stage hydraulic fracture stimulation that have been key to surging Shale Gas production and the growth of some Tight Gas plays. Each of the eight frac stages depicted in the figure is carried out sequentially, starting with the one furthest from the vertical part of the wellbore. Now over 2 dozen fracs can be done. The flow from an unconventional well mainly reflects the money invested in fraccing, not a natural flow rate, so we refer to it as a “manufactured” well. The initial rate is high, but drops off.
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Canadian Gas Reserves Replacement (2016)

This figure presents the proved gas reserve replacement for the top 30 Canadian gas producers.

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Canadian Gas Reserve Life

This figure shows the Canadian proved Gas Reserve Life Index based on proved gas reserves for the top 30 Canadian gas producers.

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Western Canada Deep Basin Gas Production Forecast

In recent years, drilling has focused on liquids-rich gas. Economics are also improved by using existing infrastructure. Since our previous cost assessment, development has focused on Lower Cretaceous plays, including the Notikewin-Falher, Wilrich, and Bluesky-Glauconite, in the southern part of the basin. The figure shows the location of the Deep Basin tight-gas plays in, as well as the dry-gas production forecast for, Notikewin-Falher, Wilrich, and Spirit River formations.

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US Gas Reserves Replacement (2016)

This figure illustrates the Lower 48 gas reserves “added” versus “produced” for the top 30 US natural gas producers. Reserves added on the charts include reserve additions through the “drill bit,” “improved recoveries,” and “revisions” of prior estimates.

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US Gas Reserve Life

This figure shows the proved Gas Reserve Life Index for the top 30 US gas producers.

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North American Natural Gas Resources

This figure shows North American natural gas resource by type of gas resource and by region. The size of the pies corresponds with the regions’ ultimate resource potential.

Ultimate resource potential is the amount of resource that could be technically recovered with existing technology or small enhancements without regard to the economics of extraction. The estimates are presented on the basis of dry gas.

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North American Gas Production – Growing Shale Gas

This chart shows North American dry-gas production to 2025 by gas type: Associated (Solution), Conventional, Coalbed Methane (CBM), Tight, and Shale Gas.

  • North American gas supply is demand driven.
  • North American gas supply mix is “Unconventional” gas—the new conventional gas.

Highlights:

  • Higher-cost conventional gas production will continue to decline.
  • Shale and tight gas growth will come mostly from liquids-rich areas of the Utica, Marcellus, Haynesville, Montney, and Duvernay.
  • Associated gas will grow due mainly to growth of tight oil production in the Permian, as well as in the Bakken, Eagle Ford, and Niobrara.
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