The current boom in unconventional oil will eventually become a powerful echo, but only after technological improvements have run their course, according to a U.S. Energy Information Administration analysis of the drivers behind domestic crude oil production.
When that “inflection point” occurs will depend on many factors, but the report from the statistical arm of the U.S. Department of Energy suggests it could be felt as soon as 2014.
Between 2011 and 2012, domestic oil production increased by 790,000 barrels per day, the largest single-year increase since Col. Edwin Drake started the oil industry more than 150 years ago. For the current year, EIA expects production to top that record, increasing by 815,000 bpd over 2012 levels. But in 2014, EIA believes the growth should slow to 570,000 bpd, reaching 7.82 million bpd, the highest average since 1988.
EIA points to technological improvements at tight oil formations in North Dakota and Texas, a continental pipeline system adjusting to the new geography of oil production, and production increases from a slate of new Gulf of Mexico developments.
While noting that future technologies could further improve the economics of tight oil, EIA expects the growth of unconventional production to slow as economics of scale reduce and companies deplete the sweet spots. Still, EIA noted, “It is difficult to predict when that inflection point will be reached because it can be pushed father into the future by increases in the number of drilling rigs and further technological change.”
Tight oil driving growthThe recent growth comes primarily from three basins, according to EIA.
They are the Williston Basin of North Dakota and Montana (home to the Bakken petroleum system and prolific middle Bakken formation member); the Western Gulf Basin of south Texas (home to the Eagle Ford formation); and the Permian Basin of west Texas (home to the Spraberry and Wolfcamp formations), with promising results also coming out of the Denver Basin of Colorado and Wyoming, and the Anadarko and Arkoma basins of north Texas, Oklahoma and Arkansas.
Of the 1.26 million bpd of total forecasted production growth between November 2012 and December 2014, EIA expects some 1.13 million bpd to come from onshore plays.
“While oil production from other sources will continue to account for most of the country’s output, production volumes from tight formations such as the Bakken, Eagle Ford and Spraberry are forecast to steadily increase tight oil’s production share, reaching about one third of total U.S. oil production by 2014,” EIA concluded in its report.
With gains in drilling efficiency, EIA expects the average daily rig count in the Williston Basin to fall over the next two years, to 184 rigs in 2014 from 208 rigs in 2012.
This, in turn, should cause production growth to slow as well. EIA is forecasting production will increase from 720,000 bpd in 2012, to 950,000 bpd in 2013, to 1.13 million bpd in 2014 and close out 2014 at just less than 1.19 million bpd. Additionally, as companies deplete sweet spots, EIA expects 30-day initial production rates to fall over the near term, from 458 bpd in 2012, to 435 bpd in 2013, to 414 bpd in 2014.
With winter weather impacting Bakken developments to a much greater degree than tight oil operations in Texas, though, EIA expects production to “surge” in the spring.
More efficiency gains to come?While the combination of horizontal drilling and hydraulic fracturing is responsible for making these formations economic at current oil prices, EIA points to a range of technologies responsible for bringing down the cost of tight oil development, and therefore increasing production this past year and likely for the next two years, as well.
Those technologies include: multi-well pads that create economies of scale for both drilling and completion activities, horizontal laterals up to two miles long that contact a larger portion of oil-bearing formations, micro-seismic imaging that improves the understanding of formations, drill bits designed specifically for shale and tight formations, and “walking” rigs that decrease the time to move from one well to another on a pad.
And EIA sees the possibility for additional technologies to further improve the economics of tight oil, including “selective fracturing” along horizontal laterals, which would avoid sections of a formation believed to have lower or no production value.
Optimizing operationsEven without additional improvements, producers are gaining efficiency.
Because of the steep decline curves common for tight oil wells, unconventional growth follows drilling activity to a much greater degree than in conventional plays and economies of scale come when producers find the optimal use for existing technologies.
In the Bakken, for instance, the average horizontal lateral is currently 10,000 feet long with 30 fracturing stages. By coming into contact with more of the formation, these longer laterals reduce risk and increase production, which in turn lowers average finding and development costs.
But, as EIA noted, because horizontal wells are more expensive per foot than vertical wells “there are diminishing returns to ever longer laterals.” And, according to a report from the oil field services giant Schlumberger, 30 stages of hydraulic fracturing appears to be the optimal amount for 10,000-foot laterals.
Some efficiency gains have nothing to do with technologies.
EIA pointed out that in the Eagle Ford and the Bakken, leaseholders have started swapping out acreage to create contiguous land positions that cover less ground and therefore require lower mobilization costs. The agency also praised the North Dakota Industrial Commission for unitizing leases in a grid of small equal plots, which “should create long term infrastructure efficiencies whereby service roads are oriented along the axes.”
By bringing down the cost of production, these gains have improved the economics of sweet spots and also increased the potential tight oil resource base by making more areas economic, but EIA believes “the rate of change in efficiency improvements is expected to slow down in the future and become more representative of the overall rate of technological improvement experienced by the oil and gas industry as a whole.”