Drilling advances: What is the Performance Twist-Off cost?

Continuing with the story from in prior columns, we’re looking at U.S. drilling activity to see how drilling performance has changed over the last few years and what it might say about how we can advance drilling even further.   

Refer to my last column, Drilling advances and where they’re headed, if you are interested in the complete story. I try to make each of these helpful as stand-alone missives, but there is a red thread running through them all, and the prior version might be useful for new readers. 

Briefly summarizing, U.S. drilling performance has advanced A LOT since the start of unconventional/shale. In fact, since 2008 by one measure (feet drilled per day) performance has doubled by going from less than 500 ft/day to over 1100 ft/day.   

Other performance measures like safety and well difficulty as measured by measured depth have also improved (see prior columns). There is a hitch though… U.S. drillers’ performance regresses when rig count jumps – it’s like there is a Performance “Twists Off” cost every time we get busier. Figure 1 shows the story.   

Prior columns explored the mathematical relationship quantifying changes in activity and changes in performance, and showed how technology has reliably improved performance over time.  

But performance definitely does regress when activity level spikes. Mathematically, when rig count goes up by X%, performance as measured by ft/day goes down by .33 * X%. It’s not just ft/day that gets worse; performance as measured by Fatality Rate gets worse too.   

The Fatality Rate goes up .65 * X% (see prior columns). This regression isn’t due to any measurable changes in well difficulty, but to our industry’s inability to reliably transfer already achieved average performance “know-how” and practices when crews and rigs are brought into the fleet. The question is, does it really have to be this way? 

Performance does recover even faster when rig count decreases, so the net effect is a continual advance in drilling performance with fits and starts. But we definitely have a Performance Twist-Off every time activity jumps – and this effect goes all the way back to 1950. 

The first half of this month’s column will explore the financial cost of this Performance Twist-Off (spoiler alert… it’s way more than you might think). The second half will introduce a few ways people are working to address this problem.   

Future columns will explore, in more detail, what people are doing to make performance as insensitive as possible to changes in activity level AND explore what is being done to advance to even higher levels. 

What might have been. Just what does the Performance Twist-Off cost? The short answer to the question is that, since 2008, it has cost U.S. operators somewhere between $10 and $20 BILLION dollars. That’s $10 to $20B that didn’t have to be spent.  How do I know?  Figure 2 shows the basis of the calculation (and the set of data is in Table 1 the end of this column).  

We know in 2009 that 1,086 rigs actually drilled 32,803 wells with an average depth of 7,073 ft, for a total of 232M ft drilled – that’s an average of 585 ft per day. We also know in 2010 the industry actually drilled 38,300 wells with an average depth of 6,781 ft, for a total of 259.7M feet drilled.    

It’s a simple mathematical fact that if U.S. drillers had drilled those 38,300 wells at the same ft/day as they had in the prior year, they would have needed 1,216 rigs to do it. Well, they actually used 1,541 rigs… 325 more rigs than would have been needed IF we’d be able to replicate already proven performance.   

Similar calculations mean that, had the industry been able to maintain average ft/day performance as activity ramped up in 2010, 2017 and 2022, the industry would have saved a total of 1,245 rig-years of effort. At a spread rate of $25k/day, that’s $11 billion, and at $50k/day, that’s $22 billion in money that – in a better world – wouldn’t have had to be spent. 

Well, maybe the wells were that much harder in 2010 vs 2009? Not likely, because in 2010, the wells were on average shallower (6,718 ft vs 7,073 ft), AND just three years later in 2013 with even deeper wells (8,183 vs 7,073 ft), the industry performed even better at 594 ft/day.   

Similar analysis for every other Performance Twist-Off shows the same thing: EVERY time activity increases, we have a Performance Twist-Off that’s related to new crews and new rigs being brought back on. Those crews and that equipment cannot duplicate what we have already done. But eventually, those same rigs and crews managed to figure out how to achieve that performance.    

Of course, the industry won’t be able to magically prevent Performance Twist-Offs unless it does something differently. The $11 billion to $22 billion wasted means that, had we spent even a fraction of that money more wisely, we could do even more with less.   

There are several ways to look at how to spend the wasted money better. In one way of looking at the problem, the industry could have quadrupled its money (e.g. had 400% return) by spending $2.9 million to $5.8 million for each new rig added. A rig was added during an activity jump IF (note the big “if”)  the money could have assured the crews would have been as skilled as the average crews, and the equipment was as serviceable as the average rigs actually were in the prior year. All that wouldn’t have been easy – but it is mathematically possible. 

Calculation: a total of 1,438 additional rigs could have drilled the additional footage during the activity jumps since 2008. The industry spent $11 billion to $22 billion drilling at lower-than-average performance. We could have spent up to $2.9 million to $5.8 million per rig getting them up to average performance and spent 75% less than was actually spent.  

What’s a mother to do? Future columns will dive deeper into what people are doing and what is yet to be done with technology, process and people to get rid of this regression AND improve even further.  

Not to leave you hanging, I’ll present two ways people are working to address the Performance Twist-Off and suggest a third.  Here are some approaches that can and do help mitigate the cost of a Performance Twist-Off. 

Approach 1: Steady as she goes  

One certain way to ensure that you are not a prisoner to a Performance Twist-Off is to keep activity flat – with slow changing rigs and crews. If you don’t swing at oil price changes, you won’t suffer the effects of performance loss as activity increases – so long as you keep the same team of contractors and crews – or you’ll at least be less sensitive to those effects. Longer term contracts also have the advantage of not potentially overpaying in “boom” years when rig utilization gets tight.   

When activity picks up, operators get double-dinged by increased rig rates and the Performance Twist-Off.  A longer term more consistent strategy can avoid the double-ding. 

One organization using this strategy is Diamondback Energy. Diamondback CEO Travis Stice announced in their 2nd quarter earnings call that they will be going down from a previously projected 12 rigs to 10 with NO EFFECT on production. Last year, they had planned on each rig drilling 24 wells but are now able to drill 26 wells. 

They projected similar efficiency increases in frac crews – increased to 80 to 100 completions per year. Planning for the long term and maybe even building in projected advancements would certainly have been a wise way to manage, since history says that it would be a good way to move going forward.  

International drillers may have an edge on their U.S. counterparts because they add rigs slower than the U.S.  This makes them less sensitive to a Performance Twist-Off disfunction. 

Approach 2: Mechanization and automation 

John De Wardt, chairman of SPE’s Drilling Automation Technical Section, makes the point that, “Automation is a big part of the solution for recovering performance fast and minimizing increase in accidents on ramp up in activity. Further, the fatality rate can be impacted by automation, especially when a fully mechanized/automated rig floor is employed, which can now be retrofitted.”   

John presented a survey of what many leading drilling organizations such as Baker Hughes, SLB, H&P, NOV and others are doing to improve automation in recent meeting of the Technical Section.  

This column is much too short to present all the things John described people are doing – in future columns, I hope to get into some of the details. Suffice it to say that automation and mechanization is one the of the ways we can protect ourselves from a Performance Twist-Off, by building successful practices into the digital/electromechanical drilling system.   

Approach 3: Crew competency 

Finally, (I don’t have space in this column to cover another proven approach to mitigating Performance Twist-Offs), intentionally manage the crew’s competency to assure that they have the skill to perform at previous levels – this is to ensure knowledge is transferred on current practices, and that the crew has the skills to execute those processes. We’ll cover more of this in later columns. 

Until next time, I hope to start a conversation with any of you on how we can all help drilling advance.  If you have any ideas, please email me at mailto: ford.brett@petroskills.com and I promise I’ll respond.   

About the Authors

Ford Brett, P.E.

Contributing Editor

Ford Brett, P.E. , is CEO of PetroSkills. He has consulted in over 45 countries, been granted >35 patents, authored >40 technical publications, and has served as an SPE Distinguished Lecturer, as well as on the on the SPE Board as Drilling and Completions Technical Director.