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Tight oil production in the United States has been growing steadily over the last years, with negative additions only experienced for the first time last year. Production growth is expected to recover this year, and is projected to increase by over one million bbl/d year-over-year on average in 2018-2020. This article examines the fundamental drivers behind this growth: drilling efficiency, well performance improvements and reduction in breakeven prices, focusing on the top US oil plays.
Figure 1 shows light oil production additions from US shale and tight oil plays from 2010 to 2020. The top four plays contribute around 80% to the production growth during this time period, and over 90% this year, with the Permian Basin accounting for most of the additions. Historically, Eagle Ford Shale was the largest contributor to production growth, followed by the Bakken/Three Forks Shale play. Going forward, increasing contributions are expected from the Permian plays, particularly Permian Delaware. In total, light oil production increased from 500 thousand bbl/d in 2010 to 4.9 million bbl/d in 2015. 2016 was the first year with negative US tight oil production additions as operators delayed drilling and completion activity in the low oil price environment. This trend is expected to be reversed this year, however, with an expected light oil addition of around 500 thousand bbl/d.
Figure 2 shows the average number of horizontal wells drilled per rig year for the top US oil plays from 2010 to 2017. In 2016, drilling efficiency in Eagle Ford and Bakken improved by almost 50% year-over-year, while the corresponding average US shale efficiency improvement was 27%. One of the key reasons for the efficiency improvement observed historically is the introduction of pad drilling, which allows operators to drill multiple wells from the same drilling location and reduces the time spent for rigging up and down. As of 2016, over 90% of all wells in the Bakken and Eagle Ford Shale plays were drilled using this method. In the recent years (2014-2016), high-grading of equipment explains a major part of the observed efficiency gains. On the other hand, drilling efficiency is estimated to decrease by around 15% on average this year, explained primarily by the higher utilization of older less efficient rigs as well as more complex wells with longer laterals becoming more common.
Figure 3 depicts the average 30-day production rate and light oil content for horizontal wells across the same selection of shale plays. The values are based on well-by-well reported production data. Historically, Eagle Ford showed the highest average 30-day IP rate in the industry. Since 2014, we have seen a notable increase in well performance across all major shale plays, and Permian Delaware exhibited by far the largest improvement – average IP rate has increased by 48%, growing from 760 boe/d in 2014 to over 1100 boe/d in 2017. Producers in Permian Delaware transitioned to drilling longer laterals, enhanced completion techniques (e.g. increased average proppant loading per perforated lateral) and focused more of the activity in the core areas of the acreage. The average 30-day IP rate in the United States across all shale plays has nearly reached 1000 boe/d in 2016. On the other hand, there has been little change in average light oil content in the industry. It stayed rather constant since 2014 at around 48-50% on average. Among the top four shale plays, Permian Midland realizes the highest percent of light oil since 2016 and is estimated to reach 86% in 2017.
Figure 4 shows average WTI breakeven prices for selected US shale plays by year. Rystad Energy analysis shows that breakeven prices have decreased by 38% on average from 2014 to 2016. The largest decrease has been realized in Permian Midland, where breakeven prices have fallen by 45%. A number of factors have been key to the successful breakeven reduction, including improvements in well performance, efficiency gains, high grading of drilling locations, lower unit prices due to service margin compression and LOE reduction. However, the impact of some of these factors is believed to be cyclical, and thus breakeven prices are likely to increase in the years to come. So far in 2017 we see an increase of around 6% on average across all shale plays, particularly driven by increasing unit prices. This, however, is not able to prevent continuous shale production additions throughout 2017. By early 2018 we expect service cost escalation to be in full stride in response to a continuous expansion of completions in 2017. As a result, for 2018, a WTI price above 55 USD/bbl is needed for the shale industry to continue its organic recovery.
Even though the oil price dropped significantly in the second half of 2014 and still remains at relatively low levels, light oil production from US shale plays has stayed rather resilient during the period, and having reached the bottom in 3Q 2016, has been on a clear growing trend since the beginning of 2017. Enhanced drilling efficiencies, improvements in well performance and high-grading of acreage amid service margin compression have contributed to significant reduction in breakeven prices, enabling producers to adapt to the low price environment and revert the production decline seen last year. Even though cyclical cost effects are expected to somewhat push breakeven prices up, a WTI oil price above 55 USD/bbl will be enough for the US shale industry to continue its growth into the next year.
Note: the original article published on 24.08.217 by PESGB magazine has been revised by Rystad Energy authors due to the updates in production forecast
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