As the shale revolution matures, a growing portion of horizontal wells are entering their terminal decline. The ultimate longevity of production from horizontal shale wells can play a significant role in understanding the future outlook for natural gas and oil supply in the US, particularly in a period of lower investment in new wells. Today’s Energy Market Insight will explore terminal decline rates and their impact on the outlook for supply.
For the purpose of today’s Energy Market Insight, terminal decline rates are defined as the period beginning after 8 years of production where the rate of decline slows to a gradual final slope. Though it is far below the well’s initial peak, the prolonged duration of this tail means that a significant part of a well’s lifetime production may come from its terminal decline phase. Small differences in the shape of terminal decline can, by extension, lead to meaningful changes in PDP projections for the region. For example, a 3.6% change in terminal decline rates for the Northeast would result in more than a 1 Bcf/d change in expected PDP production by 2025. A steeper decline from existing wells would thus require more drilling in the future to maintain current production levels compared to the shallower decline rate.
The difficulty in analyzing terminal decline is that real-world data for the shale plays is very limited. For instance, in the Northeast region, horizontal drilling in the Marcellus only began in earnest in 2008. Combined with delays in state reporting on well performance means that reliable production data is only available through 2019/2020. This makes for an 11-year window on which to base assumptions about future declines, and only for a limited sample of wells drilled early in the development of the play.
Looking to the Barnett play, where the shale boom originated circa 2004, the additional years of data might be used to foresee Northeastern declines. Barnett wells show an average annual decline of 9.5% in their terminal period. Assuming this rate holds true for the Northeast, a PDP projection yields the curve shown above.
However, without proper adjustments, the Barnett proves to be a poor stand-in for the Northeast. One reason is its much higher rate of well retirement. Steady loss of wells from the production sample has shrunk the Barnett’s production base and made for a steeper aggregate decline curve. While most Barnett wells drilled in 2004 remain in production, a full 30% had ceased reporting data by their 15th year.
In contrast, despite many temporary shut ins, no vintage of Northeastern wells has yet to exceed 10% retirement. This makes an adjustment necessary before comparing the Barnett to the Northeast. When non-producing wells, presumed to have failed or been plugged, are removed from the sample, the Barnett’s decline curve shifts drastically upward, matching the Northeastern wells more closely.
The average decline rates between year 6 and year 10 are very similar for both sets of wells. If this adjusted measure of decline is used, the Barnett’s average terminal decline rate is calculated at 5.9%. As seen above, the difference between 5.9% and 9.5% produces a meaningfully augmented PDP projection for the Northeast.
Underlined by comparing these two case studies is the extent to which terminal declines are not driven purely by technical factors. While these two regions may share a superficially similar decline curve in the out years, their real-world production is skewed by the dramatically higher rate of well retirements seen in the Barnett compared to the Northeast. If a change in conditions led to higher retirements in the Northeast, the aggregate decline rate may rise. A variety of interventions, from shut-ins to refracs, stand to alter terminal decline curves and reshape PDP, depending to what degree they are applied. For well-level and regional PDP decline estimates request a demo of our Production View data platform.
