Making shale competitive

Leen Weijers, Senior Vice President, Engineering, Liberty Energy 

FRAC’RS WORK HARDER 

The shale frac industry has never been nimbler and more efficient. With about 135 frac fleets at work in liquid-rich basins and another 40 frac fleets in dry gas basins in the United States, these crews work at the tip of the spear to make it the #1 oil and #1 natural gas producer. About 65% of U.S. oil production comes from shale, and the share is about 80% for natural gas. The conventional rock portion is shrinking.  

Efficiency comes from pumping more minutes every day, but also by cramming more into those pumping minutes. When the shale industry started scaling up for oil, it was common to frac just a few hours during most days, maybe equal to 20% of all the entire pumping time available in a year.  Today, that number stands closer to 60% of all time available—~200% increase.    

Every piece of equipment on a frac location, plus the long supply chain from sand mine and compressed natural gas distribution point to frac location, has contributed to adding minutes to pumping. Putting sand boxes on trucks; using AI to warn crews of upcoming preventative maintenance; placing sensors at the edge for logistics tracking; real-time command centers that help crews to run efficiently with the lowest fuel consumption and the best equipment longevity; all these constitute a plethora of things that have helped to safely add pump time and increase throughput.     

Fig. 1. Change since 2012 of various industry throughput metrics for a typical U.S. frac crew.

A summary of these improvements is shown in Fig. 1.  As mentioned before, pump time for frac is up 3x since 2012, while frac jobs are done at a higher average rate and at a higher overall surface pressure.  The product of these three parameters is work done, or horsepower-hours, which is up about 700% for every U.S. frac crew since 2012.  The most stunning part: for a dedicated frac crew for a year, the cost for an E&P Company is unchanged.   

These changes were exclusively achieved through competition. No tax breaks or handouts. Creating these efficiencies was done by pumping services companies to be the providers of choice for E&P Companies.  

An industry that requires months or even longer to respond to commodity price changes is naturally cyclical, as it overshoots or undershoots a price signal.  But in the deep corporate world of dozens of public and private oil companies—a depth no other country can match—that complex feedback system is becoming faster.    

BOOSTING U.S. PRODUCTION 

When the final numbers are in, U.S. 2025 oil production will likely increase slightly, while there is consensus that U.S. 2026 production may go down 1%, or about 100,000 bopd.   

Industry efficiencies and growth in pumps per fleet have boosted year-1 production per frac crew to about 25,000 bopd/fleet. That means 135 frac fleets can produce 3.4 MM bopd—which about matches the current yearly U.S. shale oil production decline. Thus, 135 active frac fleets keep U.S. oil production flat.  

Fig. 2. U.S. shale production colored by year of completion (top) and active liquid-rich frac crews for the year. For the current ~135 fleets operating in liquid-rich basins, overall shale production is expected to be steady.

On the other end of the current response to lower prices lies a potential quick response to add frac fleets back to work. If WTI prices would increase again, for example in 2027 or 2028, current near-peak U.S. shale oil production can relatively be easily tappe. In the example scenario below in Fig. 2, the model shows how quickly U.S. oil production can react when frac crew count grows by ~10%—from 135 back to about 150 frac crews by the end of 2027. By the end of 2028, assuming the same frac fleet production metric of 25,000 bopd/fleet still applies, U.S. shale oil production could grow again by 400,000 barrels a bpd.    

Frac crew efficiency and throughput may still be further increased, for example through the increased application of simul- or trimul-fracs.  Pumping into two or three wells at the same time, at a higher combined rate but a lower rate per well, provides a means to lower wellbore friction. This allows pumping companies to increase throughput more than horsepower requirements. Another way to further boost throughput is to drill longer laterals and place more wells on a single pad, requiring fewer frac crew moves between pads, and thus increase the number of pumping days in a year.   

These potential gains may neutralize frac fleet productivity through decreasing rock quality and local reservoir pore pressure, due to depletion from existing nearby wells. As of now, frac fleet productivity has been steadily increasing.  It is likely, however, that these countering forces will at some point eclipse efficiency and throughput gains.  

MAKING SHALE COMPETITIVE 

These improvements have greatly impacted well production and cost. The increases in throughput have allowed fracture treatments in shale wells to grow dramatically in lateral extent; in slickwater volume used per well and per lateral foot; in sand used per well and per lateral feet; and, with more effective perforation clusters from which fractures can initiate and grow. All these increases have had two results for fracture systems: increase the size and the density of the fracture network created from each well into the shale formation. The resulting increase in fracture surface area has long increased well productivity, but current productivity per foot in year 1 has peaked, and well productivity for year 1 is at or near its peak.  

Fig. 3. U.S. shale well cost (top left) and well production (bottom left), as well as the cost per barrel oil ($/BO) produced in year 1 of a shale well’s lifetime.

But ultimately it is not about productivity. It is not about cost. It is about production economics.  The simplest way to express that, without incorporating a time value of money, is the cost to produce a barrel of oil.  In Fig. 3, we have slightly modified this to mean the drilling and completion cost to produce the barrels in the first 365 days of a well’s productive life. The benefit of that metric is that we can measure it (after a year), and that we don’t have to resort to a modeling exercise.  

Where the story of well cost reduction and well productivity increases is exceptional, the $/BO graph tells an even more remarkable story.  In every liquids-rich basin in the U.S., that cost has been reduced by 60% to 75%. When comparing to a WTI price, and remembering that our production metric is only for year 1, it means that, between 2010 and 2014, the time to breakeven was more than a year. Today, for this simple metric, breakeven time is significantly shorter than one year.      

Our story does not end there. While innovations and efficiency gains at Pumping Services Companies have led to more throughput for E&P company dollars, overall oil prices for consumers have come down dramatically from their elevated levels in 2010–2014. Currently, at a price of $60/bbl, leveraged by shale barrels that make up almost 10% of world production, consumers around the world are saving $30-40/bbl, or about $3 billion to 4 billion daily.  

That’s the impact made by maybe about 30,000 people working on the front lines in our oil fields, on drilling rigs and on frac crews.   

LEEN WEIJERS serves as the Senior Vice President of Engineering at Liberty Energy. He has worked at Liberty since its founding in 2011, originally serving as its Business Manager. Mr. Weijers’s role at Liberty focuses on two main aspects. One, delivering improved well economics to customers through optimized frac designs, and two, on customer and internal data sharing and reporting to improve business efficiencies. Mr. Weijers worked at Pinnacle Technologies from 1995 to 2011, where he oversaw the development of the industry’s most widely used fracture growth simulator, FracproPT. He was Pinnacle’s Rocky Mountain Regional Manager from 2007 to 2011, where he helped rebuild its Rocky Mountain operations. He has authored dozens of industry courses and publications. He also played a key role in the calibration of fracture growth models with various fracture diagnostics such as tiltmeter and micro-seismic fracture mapping technologies. Mr. Weijers completed his doctoral research at the Faculty of Mining and Petroleum Engineering at Delft University of Technology in the Netherlands by conducting fracture growth model experiments to investigate the interaction of hydraulic fracture systems with horizontal and deviated wells. Before that, he completed a Master’s degree in geophysics, also from Delft University of Technology.