7 Ways Operators Are Improving Alberta’s Duvernay Shale Play

Alberta’s Duvernay shale has moved from exploration into the early stages of commercial development.

The play, which is estimated to hold 820 tcf of natural gas, as well as more than 300 billion bbls of oil and natural gas liquids, has become a significant area of focus for some of Canada’s largest players.

A new report released this week by CanOils, the Daily Oil Bulletin and Baker Hughes, a GE company reviews Duvernay drilling performance, uncovering — among other insights — seven ways that operators are improving as the play matures.

1. Top tier rigs

High performance drilling rigs featuring AC drive systems, automated pipe handling, walking systems, large pipe-racking capacities and the ability to drill with stands as long as 90 feet dominate the Duvernay. The top tier rigs, combined with access to the best crews due to the slowdown in activity in the last three years, have driven drilling productivity upwards across North America and the Duvernay has benefitted.

2. Average lateral lengths increasing

Lateral lengths have been rapidly increasing in the Duvernay since 2014, rising by 42 per cent by year-end 2017 as operators worked to lower costs per boe of production. There was significant variation in lateral lengths, however, as different operators in different stages of development tested out well designs.

In 2014, lateral lengths varied from 1,200 to 2,400 metres. In 2015, upper range lateral lengths climbed to 2,800 metres. By 2017, the largest cluster of laterals drilled in the play was in the 2,500 to 3,000 metre range. There have been some outliers, including a 7,770-meter lateral drilled by Shell Canada.

3. Faster drilling speeds

Duvernay drillers have more than tripled metres per day since 2014, to more than 350 metres per day in 2017 from just over 100 metres per day in 2014. Part of this has been an improvement in drilling technology, but the move from exploratory drilling to pad development is likely the cause of much of this gain.

Click here to download the full report, Managing the curve: Lower capital costs and improved productivity make the Duvernay liquids and oil plays possible, but operating costs will drive profitability

4. Drilling costs decline

The cost per metre drilled declined by 38 per cent in the Duvernay from 2014 to 2017 (to about $500 per metre from $1,300 per metre), due to increased rig efficiency and lower day rates due to the decline in general activity.

5. Fracture stage counts up rapidly

With the ability to drill longer laterals, Duvernay operators have been able to rapidly increase the number of fracturing stages per lateral, but there is substantial variation between wells. In 2015, the majority of Duvernay wells were stimulated with between 25 to 35 stages. That changed in late 2016, when there was a bump in wells with fracture stages ranging from 45 to 95 stages.

6. Estimated ultimate recovery increasing

The combination of longer laterals and greater completions intensity is paying off in higher estimated ultimate recoveries in the Kaybob Duvernay. EURs have increased by 63 per cent as the play has moved from exploration to early development.

7. Capital cost per boe of EUR down significantly

One measure of success of oil and gas explorers and producers is how effective they are at converting their capital into recoverable resources. Duvernay operators have seen capital costs per boe of EUR decline 46 per cent, to $10.89 in 2017.

While the report notes that cutting capital costs per boe recovered is a major step in commercializing of the liquids rich Kaybob Duvernay and East Shale Duvernay plays, ultimately managing production to keep wells operating as long as possible will determine their profitability.

This is a function of high early decline rates, meaning that despite strong initial production rates most of the expected ultimate recovery of resources will happen well after the first few years of production.



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