Innovation is key performance driver for modern gas wells: Montney Formation one of North America’s biggest gas resources

Source: IHS-Performance Evaluator for well locations and the Atlas of the Western Canada Sedimentary Basin for the location of the Montney Formation. Description: This map shows the location of the Montney Formation in a belt 200 km wide that stretches near Edson and Hinton, Alberta, in the southeast to near Fort Nelson, British Columbia, in the far northwest. The map also shows the location of Montney wells drilled since 2005, which are largely located on the Montney’s south and western sides.

Montney wells drilled in 2016 each expected to produce a total of 7.2 Bcf of gas, 4 times the 2005 value

Two things determine how much oil or gas a well will produce: the quality of the reservoir the well is drilled into, and the technology applied to the well, according to the National Energy Board.

One way to get better results from new wells is to find better reservoirs to drill.  This is why companies drill their best prospects first, and why it becomes harder over time to find high quality reservoirs.

The other way to improve the performance from new wells is to improve the technology applied to them. In particular, horizontal drilling and multi-stage hydraulic fracturing have continually improved after being widely deployed in Canada and the United States around 2007.

In general, the performance of new wells has continued to improve since then.

The Montney Formation is located in western Canada and has an area of 130 000 km², about the size of New Brunswick and Nova Scotia combined. The Montney has the potential to produce a total of 449 trillion cubic feet (Tcf) of natural gas with modern technology, making it one of the biggest gas resources in North America.

The estimate was published in 2013 and it is likely that the amount of recoverable gas would be higher if based on current technology.

In comparison, Canada consumes about 3.2 Tcf of marketable gas per year.

However, only a small part of that large area is currently being developed. The large majority of the gas is found in only 35 000 km² on the Montney’s west side.

Of this, “core” areas of 25 000 km² are of the most interest to gas producers. Core areas are developed first because they tend to have the best reservoir quality and can produce the most gas. This is a simplification. Other factors can influence where core areas are located.

For example, natural gas rich in liquids like propane, butane, and condensate, which earn more revenue, can cause industry to focus on some liquids-rich areas while ignoring areas with “dry” gas.

The figure below shows monthly gas production from average Montney Formation gas wells drilled from 2001 to 2017. The large majority of Montney wells were drilled in core areas over this time. Each well shows the same trend: gas production quickly ramps up for the first 1 to 3 months before peaking, after which production begins a steep decline followed by a more gradual decline.

This “decline curve” shape is not only typical for Montney Formation gas wells, but wells in almost all formations that produce tight gas and tight oil (including shale gas and shale oil).

Source: IHS-Performance Evaluator

This figure shows that technology has helped newer wells outperform older wells. Peak production rates were 0.9 million cubic feet of gas per day (MMcf/d) for wells drilled in 2005, but more than quadrupled to almost 4 MMcf/d for wells drilled in 2017. After 5 years of production, newer wells continue to have higher rates of production. A well drilled in 2005 typically flowed 0.2 MMcf/d after 5 years while a well drilled in 2012 flowed 0.7 MMcf/d. Wells drilled after 2012, which do not yet have 5 years of available production data, could have higher 5-year production rates as well.

The total amount of gas Montney wells will produce over their lifetimes is also expected to increase for newer wells. Better performing wells have a higher “estimated ultimate recoveries”, or EURs(An EUR is a calculation of how much oil and gas a well will produce over its lifetime. EURs are determined by analyzing the rate at which a well’s historical production declines and then applying a projection from that into the future. In this case, wells were assumed to produce gas for a total of 30 years).

Source: EURs: NEB analysis of IHS-Performance Evaluator data, Fracture stages: IHS Performance Evaluator data

Montney gas wells drilled in 2005 are each expected to produce a total of 1.8 billion cubic feet (Bcf) of gas, but improving technology since then means that wells drilled in 2016 are each expected to produce a total of 7.2 Bcf of gas, 4 times the 2005 value.

Increasing well performance of newer wells in the Montney Formation is consistent with companies continuing to drill high-quality reservoirs in their core areas while technology continues to improve. Much of this improvement is likely from increasing the number of fracture stages and the lengths of wells. As a result, each well is in contact with a larger volume of fractured rock and can flow more gas.

Because of the large size of the Montney’s core area, companies will likely take many years to fully drill areas with the best reservoirs before they start drilling areas with lower reservoir quality. Therefore, it is likely that Montney well performance will continue rising as technology continues to evolve.

Well performance in other plays could evolve differently, however. Generally, the larger a play’s core area, the more potential it has for well performance to continue growing over time. However, oil and gas plays with smaller core areas have greater potential for their high quality reservoir to be drilled up more quickly, meaning producers would have to start drilling lower quality rock sooner rather than later.

Well performance in plays where drilling is moving from core areas to non-core areas could evolve in three ways:

  1. Improving technology could possibly outpace declining reservoir quality and the performance of new wells could continue to increase.
  2. Improving technology could keep pace with declining reservoir quality and the performance of new wells could be the same as older wells.
  3. Improving technology may not be able to keep pace with declining reservoir quality and the performance of new wells could start falling compared to older wells.


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