Drilling advances: Bottlenecks? What bottlenecks?

FORD BRETT, CONTRIBUTING EDITOR

The last column surveyed the demand for natural gas in the U.S. through 2030 and assessed what that might mean for drilling. The short answer: while Most-of-the-World gas demand will LIKELY grow, since U.S. LNG export capacity WILL double by 2030, and AI / data center-driven U.S. electric power demand is set to increase by about 500 terawatt-hrs., U.S. gas demand will CERTAINLY grow.  Probably by ~30 Bcfd (~25%) by 2030.  That’s a FASTER percentage growth with greater absolute additions than ever before.  The last 30 Bcfd additions took nine years (2017 to 2025). This will need to happen in five.

The previous column showed that the gas exists, we know where it is, and we can get it out of the ground. But there are some rubs. One thing that will make the next 30 Bcfd a bit different than the last is that much of the most recent 30 Bcfd additions came from the gas associated with unconventional oil production. With flatter oil prices, unconventional oil is unlikely to continue to grow as in the past, so that avenue of increased gas production is closed. The U.S. will need to pivot to gas wells to meet demand. Right now, there are ~125 rigs targeting gas in the U.S. To add 30 Bcfd we’ll need to add something on the order of 125 to 200 rigs.   

The previous column answered the question:

• What will the growth in U.S. LNG export capacity and electricity demand for AI (and other uses) mean for the drilling business? Answer: It will increase demand for natural gas by some 30 Bcfd by 2030.

This column will answer:

• What could prevent drillers from making this expanded production a reality? Just what are the bottlenecks to producing an additional 30 Bcfd?

Refer to my last columns if you are interested in the details supporting why I think this growth will happen.  I try to make each of these helpful as stand-alone missives, but there is a red thread running through them all and prior articles might be useful for new readers.

Fig. 1. U.S. unconventional resources & production.

One small side note about “Most of the World.”  The next few columns will focus on the situation in the U.S. That doesn’t mean that drillers in Most of World won’t face similar opportunities and challenges. Many of the U.S.-specific considerations discussed below will apply to Most-of-the-World. Global data center demand for electric power is set to quadruple in 10 years by some 1,000 terawatt-hrs. That’s a faster growth rate than in the U.S. Future Drilling Advances columns will zoom in on the situation outside of the U.S. and explore the drilling issues there and some possible solutions. 

What ARE NOT Bottlenecks: The next two “Not Bottlenecks” would certainly have been bottlenecks in the 1980s through 2010. Drilling and completion advances mean that two of history’s most important limiters to production are no longer a problem.

NOT Bottleneck #1: Knowing where the gas is. We know where the gas is, and we can get it.  In the past, the industry has not known where the resource was—we were always worried about how we are going to run out. That’s not our problem now. Figure 1 shows the Texas Bureau of Economic Geology’s assessment of unconventional resources. It shows that knowing where to find the gas is not the problem. The U.S. Energy information Agency (EIA) estimate of 86 years is based on "technically recoverable resources," which includes both proved reserves and unproved resources that are estimated to be recoverable with current technology. The additions will likely mean, though, that the Marcellous and Utica shales will need to become more important contributors. 

Fig. 2. U.S. drilling performance since 2000.

NOT Bottleneck #2: Knowing how to get the gas to the surface. Figure 2 shows how drillers, along with our brothers and sisters in production, facilities, land, legal and finance have removed the drilling performance as a limiter to production. The figure shows that performance (measured by production, average feet per rig per day, and average well depth) has increased 140% since 2010, all while active rigs have declined by 74%. We use one quarter of the rigs that we used in 2010 to produce more than twice as much. That’s 800% improvement in production per active rig. Of course, this isn’t all just ‘drilling’ (e.g. making hole); completions have played a critical role.  But more effective and economic drilling makes it possible—if you can’t drill a long lateral cheaply enough, completing it won’t help.  As one example, the Marcellous laterals average >15k feet (~5km), and 20k-ft laterals are routinely drilled and cased in 25 days.  Knowing how to drill and complete a well isn’t the bottleneck.

You’ll have to take my word for it, because it’s not so clear in Fig. 2, but if we zoom into the last few years, we see that things are still getting better. Since 2024, production is up 8% while active rigs are down 16%. Improvements will have to stop at some point—I guess—but it hasn’t stopped yet and doesn’t even seem to be slowing down that much.

This is all good news, but we still have challenges.  

Fig. 3. U.S. Lower 48 production by well vintage (2010-2024).

The Red Queen problem. We know where the gas is, and we know how to get it out of the ground, but that doesn’t mean we don’t have challenges. In 1871, Lewis Carroll did a good job of describing the main challenge we face in ‘Though the Looking Glass’…

"Now, here, you see, it takes all the running you can do, to keep in the same place. If you want to get somewhere else, you must run at least twice as fast as that!" -- The Red Queen

Figure 3 shows the “Red Queen effect,” as it applies to U.S. gas drillers. To increase production, you need to drill more wells. Since unconventional wells have steep declines, you need to keep drilling, just to maintain production and will need to drill even more to increase production. You need wells to stay flat, and you need even more, if you want to grow. That means we’ll need to add rigs.

Just how many rigs? That, of course, depends on how many wells they drill per year, and how much those wells produce. Reasonable assumptions, based on current drilling efficiency and gas well productivity, indicate we need twice or maybe two-and-a-half times as many gas rigs as are active now. That’s maybe an additional 120 to 180 rigs. 

Q: Do the rigs exist?

A: Yes. As of January 2026, there are some 585 active rigs in the US (about 125 targeting gas). In 2022, we had 725—that’s some 140 more than we have now. In 2022, those rigs were working mainly on unconventional oil prospects; refocusing on gas would be possible. Those rigs are not working now, but they are somewhere and are likely fit for unconventional gas wells. The equipment exists, but do the people?  If we pay people enough, then we can get people… “head count” isn’t an issue. The first bottleneck, though, shows that “head contents” can be.

Bottleneck #1–Adding rigs causes us to go backward: The performance twist-off problem. While the bottleneck might not be existence of the equipment, getting those rigs active again with crews performing as efficiently as 2025 is not something that the industry has done well in the past. 

Fig. 4. U.S. drilling performance vs change in activity.

Past columns described the economic impact of the phenomenon (See Column—Drilling Advances (Brett) What does the performance twist-off cost?).   

Figure 4 shows that every time rig count increases, performance declines… the industry doesn’t have a good track record of being able to bring rigs back and have them operate as efficiently as they did when they quit. We can bring rigs back, but it takes time and costs $3 million to $5 million per rig in lost drilling efficiency. Bringing rigs back into service doesn’t mean you have the people (rig crews, engineers, geologists, logistics, etc.) to use them properly. Later in this series, we’ll address ways that industry might be able to address this $1 billion challenge.

Bottleneck #2-Infrastructure and midstream bottlenecks–no pipelines, no gas. Increasing production by 30 Bcfd requires long lead time and timely investment in pipelines, processing plants, compression and storage. While significant pipeline expansions are under construction, especially in Texas and Louisiana, permitting delays and legal challenges remain common, particularly for interstate projects. Permitting challenges make large growth in the place the most gas is, the Northeast, problematic.

Moreover, much of the new pipeline capacity planned through the late 2020s is geared toward feeding LNG export terminals, rather than balancing regional markets. This export-oriented infrastructure may leave some producing regions vulnerable to localized bottlenecks, limiting their ability to ramp up supply efficiently. These localized infrastructure bottlenecks increase risk and cause producers to hesitate, because they don’t want to be left with stranded gas. Before folks will commit to adding production, there will need to be some kind of certainty that we can move the gas. Production in the Bakken shale grew with limited pipeline capacity, because oil can be transported by rail in a pinch. Not so with gas.

Bottleneck #3 – Permitting… Which means political will. Finally, in traditional oil field states (Texas, Louisiana, Oklahoma, etc.), permitting is normally limited by land, title, division orders, etc., with the drilling permitting being nominal—normally 30 days or so. In the Marcellous and Utica plays, the oil industry is not as welcome. In fact, in New York, it is effectively banned. This can extend permitting, never mind more complicated land, title, etc., to multiple months. All these delays increase costs, not just by the added administrative cost, but by stretching the time from investment to first oil or gas, which materially reduces return.

Environmental regulation represents another challenge. Federal and state policies targeting methane emissions, flaring, and water usage increase compliance costs and extend project timelines. Methane regulations, in particular, require investments in monitoring, detection, and mitigation technologies across upstream operations. While these measures improve environmental performance, they add to the cost and complexity of production expansion.   

Maybe worse than drilling, our brothers and sisters in pipeline and LNG infrastructure face additional scrutiny under U.S. environmental review processes. Even with recent efforts to streamline permitting, large projects remain exposed to litigation risks and policy shifts, creating uncertainty for long‑term investment decisions critical to supporting production growth through 2030.   

Not sure what the industry can do about all this; normally, throwing money at a problem can solve it. It is not so clear that this will work in the case of permitting and regulations.    

Life is funny. I used to think that if we knew where the resource was and had the technology to get it, then life would be great. Turns out, we still have challenges. 

The next edition of Drilling Advances will explore what the industry may be able to door—not do—about these bottlenecks.   

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 questions, ideas, comments or corrections, please email me at ford.brett@petroskills.com and I promise I’ll respond.