August 2016 

Terminal decline observed from actual shale well data is higher than consensus

NASWellCube 

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Speaker: Mike McCormick, 
Senior Analyst 

Date: August 17, 2016
Time: 5.00pm-5.30pm CEST 

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DUCs in Shale - What has not yet been told?

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Speaker: Artem Abramov, 
Senior Analyst

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ArticleUnited States now holds more oil reserves than Saudi Arabia

 


ArticleAverage shale wellhead breakeven prices are below 40 USD/bbl

 


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Actual production well data supports clear improvements in initial decline rates for shale wells. However, there is limited evidence for sustainability of long-term decline profiles, which affect the EUR (Estimated Ultimate Recovery). By using the Modified Arps model to predict shale production profiles, early production data often suggests high hyperbolic factors, which result in nearly flat production profiles 5-6 years after start-up. Terminal decline assumption is commonly used and a typical lowest annual decline rate is set to 5-8%. Empiric data for early shale wells suggest that this assumption is too optimistic.

Annual production declines for Bakken and Barnett wells that started before 2010 show that after seven years on production, both oil and gas shale wells struggle to achieve annual decline rates below 10%, as shown in Figure 1. This includes only active wells, which have not been refracked. Bakken analysis becomes inconclusive after seven years due to the steep reduction of data points.

 

A terminal decline rate assumption significantly affects the EUR of a well. Figure 2 shows the sensitivity of the EUR to various terminal decline rates for a typical Bakken well put on production during 2015-2016. Such a well would have a typical well curve with a 24-h IP = 1,100 boe/d, initial decline = 2% and hyperbolic factor = 1.5. By using the Arps model without a terminal decline, the 30-year EUR based on these parameters is 650 kboe. Yet, even though a typical shale well produces almost half of the ultimate recovery during the first 5-6 years of well lifetime, a terminal decline assumption of 10% leads to a 15% lower EUR compared to the pure hyperbolic decline profile without terminal decline.

 

A terminal decline rate assumption also affects the wellhead breakeven of a well. Figure 3 shows the sensitivity of the wellhead breakeven oil price to different terminal decline assumptions for the same average Bakken well put on production in 2015-2016. A terminal decline of 10% increases the wellhead breakeven oil price from 46.8 USD/bbl to 49.3 USD/bbl, or by 5%. The effect of terminal decline on the breakeven price is less significant than on the EUR since a well typically produces nearly half of the EUR during the first 5-6 years of production. During this time, both the Arps model without a terminal decline and the Modified Arps model with terminal decline normally exhibit the same production profile.

 

Naturally, due to technological advancements, EOR programs and refrack potential, the production profiles of old shale wells may not be completely relevant for future inference. Regardless, with lack of more relevant data, the empirical evidence suggests that it is too early to justify terminal declines below 10%.

Meet us at NAPE booth #2626 to discuss further shale well analysis!