In an effort to maximize well-productivity in the current low oil-price environment, operators in North America have adjusted their completion designs and substantially increased their proppant use. At $50 oil prices, we expect to see that trend continue—particularly in the Permian, where our analysis indicates that proppant intensity will rise by 35 percent before reaching optimal economics. The resulting increase in North American demand—up from 45 million tons in 2016 to 110 million tons in 2018—will be a boon for suppliers, and a key driver of low-cost sand flooding into the Permian.
Finding the ‘sweet spot’
The length and severity of the downturn has forced operators to find new ways to increase production. Among North American E&Ps, two primary methods have emerged: confining drilling to top-tier acreage and introducing more aggressive completion designs for new wells (exhibit 1). Since implementing these practices, operators have realized annual productivity increases of 15 percent, up to an average 30-day initial production (IP) rate of 3,800 barrels per 1,000 lateral feet. Based on these observed IP increases, we anticipate that North American shale basins can sustain a 10 to 35 percent increase in proppant loading intensity before becoming uneconomic at an oil price of $50 per barrel.
Each basin’s relationship between proppant intensity and IP is different, and for each basin there is a point at which the optimal net present value (NPV) is reached and pumping additional sand into a well becomes uneconomic. However, identifying where this “sweet spot” exists is not straightforward. As an example, we have analyzed the different optimal points for two North American unconventional plays—the Bakken basin and the Delaware-Wolfcamp sub-play of the Permian basin—by examining the impact of increasing proppant intensity on NPV.
Bakken proppant intensity
The Bakken was one of the first shale plays where operators began extensively applying unconventional drilling techniques, so operators have been able to use several years’ worth of data to inform their decisions regarding lateral lengths and proppant loading intensities. Completions data from the first half of 2017 indicates that while lateral lengths have changed relatively little over the past year, operators have continued to push the limits on proppant intensities. In fact, average loading has increased from ~800 pounds per foot in 2016 to nearly 1,000 pounds per foot as of mid-2017.
By performing a sensitivity analysis on proppant intensity, we can see that operators in the Bakken have limited growth potential from current intensity levels before the incremental pound of proppant negatively impacts NPV—observed after ~1,100 pounds per foot (exhibit 2). Given the speed at which proppant usage is increasing in the basin, the Bakken may reach this point as soon as mid-2018, after which additional moves toward higher proppant intensities will likely diminish the value of the well.
Permian proppant intensity: Room to grow
Characterized by strong growth and low breakeven prices, the Permian has experienced rapid changes in well design as operators test ever-greater proppant volumes in the Midland and Delaware sub-plays. Since 2014, proppant volume per well in this region has more than doubled as operators began using low-cost local sand in fine grain completions.
Despite the basin’s strong growth in proppant intensity, the Permian—unlike the Bakken—does not appear to be near its optimal loading potential. For example, the Delaware-Wolfcamp sub-play has an average current proppant loading of nearly 2,000 pounds per foot, yet could realize up to a 35 percent increase in proppant intensity before approaching its “sweet spot” in proppant loading per foot (exhibit 3).
Supply and logistical challenges
This trend toward greater proppant loading comes as sand suppliers have announced a surge of in-basin supply—over 40 million tons of local sand capacity has been announced. And while it would initially appear that an increase of this magnitude would result in chronic oversupply, we’re expecting Permian proppant demand to increase from 13 million tons in 2016 to 38 million tons in 2018. As a result, we’ll see relatively high utilization rates (~70 percent) of this cheaper, fit-for-purpose supply. Interestingly, even if the price of proppant increased by 50 percent, the optimal proppant loading per basin would not significantly change—although NPV would decrease—indicating the relative resiliency of the “high proppant intensity” trend to pricing.
Assuming that the projected demand materializes and that supply exists to meet it, there remain two major factors that could create headwinds for the proppant market: transportation logistics and pressure pumping capacity. Challenges with proppant transportation tend to center around last-mile logistics, as the proppant is moved from a rail station to the wellhead via truck. West Texas roadway infrastructure, in particular has become progressively more congested as each well requires delivery of several million pounds of sand. Even sourcing enough drivers for all these trucks has proved difficult.
Similar issues have been observed by companies providing completions services, as the growing rate of drilling over the past year has stretched existing frac crews beyond available capacity. This problem has been exacerbated by the rising volume of sand that each well demands and the additional time it takes to pump these larger volumes. Although both service companies and producers are aware of these issues and are attempting to address them, it is too early to tell how these problems will be solved or if they constitute major bottlenecks to the ability to increase proppant loading and overall demand.
Provided these concerns can be resolved, there are implications for both the North American proppant market and the global oil market. Demand for proppant will grow in basins like the Permian, which exhibits both strong drilling activity recovery and capacity to increase proppant intensity levels. The need to pump more proppant may put continued upward pricing pressure on completion-related oilfield services, which have already seen 20 to 30 percent increases in the past year. Even with this potential rise in costs around services, the resulting production gains and increases in well NPV will keep shale oil production profitable at prices of $50 per barrel. With the high likelihood of maintaining profitability and competitiveness in a low-price environment, North America shale oil will continue as a key contributor to the global oil supply stack for the near- to mid-term future.