LONDON — Since the early days of U.S. shale development, we have observed impressive efficiency and well productivity gains realized by E&P companies. These gains were triggered by a gradual learning process, optimization of completion techniques and well configuration, and high grading of drilling locations and equipment. In particular, the shale industry has been able to survive throughout the worst downturn in history, entering 2017 in a much leaner and fitter shape. With continuous focus on unconventional development, latest trends in the U.S. offshore are often overlooked by the market. Meanwhile, a pipeline of new deepwater projects, sanctioned prior to the downturn, lifted crude and condensate output in the Gulf of Mexico (GoM) by 400,000 bpd over the 2014-2016 period. Based on preliminary production data, GoM produced 1.73 MMbpd of oil in December 2016, that is just 20,000 bpd below the all-time high output achieved in September 2009.
Not only shale, but also Gulf of Mexico development was subject to significant improvements in the drilling efficiency in 2015-2016. Figure 1 demonstrates how average footage per rig-day evolved across the U.S. in 2011-2016. The numbers are calculated as a ratio of total footage to total drilling days (including only the time from spud to total depth). Indeed, shale drilling exhibits continuous improvements due to the growing popularity of pad drilling and a shift towards high HP rigs. Permian lags two years behind other more mature shale plays as the share of test activity remains high and pad drilling remains limited, particularly in the Delaware basin. Nevertheless, average drilling speed increased by more than 100% in the Permian from 2011 to 2016. Both shelf and deepwater development in GoM did not exhibit any signs of efficiency gains prior to 2015 with average drilling speed fluctuating in the 350-450 ft/day range. This flat development trend changed drastically in 2015-2016 when average drilling speed increased by 60-75% in the Gulf of Mexico. In the case of GoM shelf, this was achieved through the severe high grading as drilling activity declined by almost 90% in 2014-2016. However, in deep water areas drilling activity stayed relatively flat at 25-35 wellbores per quarter (including sidetracks), indicating an overall higher attention of E&P companies to capital discipline and a focus on optimization of drilling operations. It is worth mentioning that average drilling speed across conventional onshore reservoirs is significantly lower than for other activity types, as remaining conventional infill drilling is often carried out by the least efficient low HP rigs.
Well productivity improvements in GoM deep water have been more significant than the recent improvements in shale. Figure 2 shows average oil well decline curves across all shale oil and GoM deepwater wells in two different periods: 2011-2013 and 2014-2016. Average shale oil well productivity increased by 38% in the first 1.5 years after a well is turned-in-line from 2011-2013 to 2014-2016. The improvements were predominantly driven by the growing contribution from horizontal wells and boosted well configuration: longer laterals, more frac stages per lateral, increased proppant and fluid intensity. However, the average productivity in the first 1.5 years improved even more, by 41-42%, in GoM deep water over the same period. Significant uplift in average well productivity was caused by the high contribution to the average from several deep-water installations in 2014-2016 (e.g. Jack/St. Malo, Lucius) where a typical well produced at the rate of over 10,000-12,000 bpd for more than 12 months. An average recent GoM deep-water well produced 3.6 MMbbl of oil over the first 18 months.
U.S. oil production peaked in first-quarter 2015, before entering into a consistent decline phase amid collapsing activity across major shale oil reservoirs. Figure 3 provides an overview of quarterly U.S. oil production additions in 2014-2016 by region and an outlook for 2017. The largest cumulative decline during the downturn was delivered by the areas covering major shale liquid plays outside of the Permian basin. Total oil output from the Williston basin, Eagle Ford, Mid-Continent (Oklahoma) and the Rockies (DJ and Powder River basins) contracted by 830,000 bpd from first-quarter 2015 to fourth-quarter 2016, declining every quarter. Another 370,000-bpd decline came from the conventional Lower 48 fields, excluding GoM and Alaska. Only two sources of oil supply in the U.S. remained exceptionally resilient throughout the downturn: the Permian Basin and the Gulf of Mexico. The Permian Basin’s output was growing every quarter, adding 300,000 bpd from first-quarter 2015 to fourth-quarter 2016. While exposed to seasonal disruptions, GoM’s production was able to deliver a 240,000-bpd growth over the same period, contributing almost equally with the Permian basin to the limited decline pace of the total U.S. oil production.
Recent growth in rig counts across major liquid onshore fields and the maturation of base production suggest inevitable acceleration in the pace of additions from the Permian basin already during first-quarter 2017 and from other major shale plays during second-quarter 2017. Shale is then set to become the major source of production growth in 2017. Nevertheless, the evolution of deep-water start-up activity in 2H-16 positions GoM for the prolonged growth in 2017. Unless GoM faces other unplanned outages on top of the recent fire on Phillips 66’s Paradis Pipeline Station, an all-time high oil output will be renewed already in first-quarter 2017.