Going Horizontal

Spreading out far and wide—what are the limits of long laterals?

 

In the shale revolution, the vertical sections of wellbores don’t do much for production—they’re a means to an end. So, the longer the laterals connected to each vertical hole, the more of the formation is exposed to production. Meanwhile, an ancillary benefit of long laterals is a reduction in the total number of wells to be drilled. For insight into the history, the driving forces behind the growth, and the limitations of long laterals, we will hear from Raoul LeBlanc, Vice President for North American Unconventionals for S&P global Commodity Insights.

That formula has also led producers to push the boundaries of technology in several facets of production. Obviously, drillers must be able to drill further and further out, which in itself is a huge challenge. But after that comes completions, including coiled tubing, cementing, and all that’s entailed in those procedures. They also must increase the length and power of their tools to help make the oil flow.

Nine Energy Service handles many completion procedures. Nick Pottmeyer is President of Completion Tools Operations for the company, and Joe Huwel is President of Cementing and Coiled Tubing. Both lent their insights into ways Nine is moving forward in accessing longer laterals.

 

Starting Small, then Growing by Leaps and Bounds

Early in the shale revolution, before about 2012, 5000-foot laterals were the new and challenging thing in the Permian Basin. After much trial and some error, the industry mastered that and was ready to expose more and more of the formation to production.

In a few years, LeBlanc noted, lengths had grown to 7,500 feet—and about that time the 5,000-footers rode off into the sunset. Hardly any of the latter are drilled any more.

From there, popular lateral lengths have grown in leaps of 2,500 feet at a time—at least for those with leases big enough to support drilling longer. Averages of 10,000 were standard by 2018, when 12,500 became the new norm, LeBlanc observed. Three miles—about 15,000 feet—began trending in about 2023. His data shows a few wells inching into the four-mile category in recent months. LeBlanc cited ExxonMobil as among those drilling the longest laterals.

 

Who’s Drilling What?

In fact, he noted company size closely correlates with length preference. The supermajors are more at the 15,000-foot level, “But the large independents are slightly less than that, closer to 12,000,” and then the private companies are lower than that.

LeBlanc listed three issues that drive length decisions, and how they play differently according to company size.

Number one is cost effectiveness. “Sure, drilling a longer well is great, because you don’t have to re-drill the vertical portion of the well,” he pointed out. But longer wells mean pushing pipe farther in, where the hole is flat, so the friction of pipe scraping the bottom of the lateral creates greater resistance—needing more power to push—with every additional foot drilled. So it saves some costs but adds others.

Part of the cost effectiveness revolves around the surface footprint—something for which he cited Exxon in particular. “You have to pay surface owners (for the land used for pads, roads, and other issues), so if you don’t want to do that, you spread wells miles apart.”

A Google satellite view shows that the surface area of today’s long-lateral wells has reduced surface usage by about 90 percent compared to that of conventional wells, he said.

Second is the resulting risk. “You have more capital exposed. A longer well is more complex than a shorter well, so there’s a risk factor.” If anything goes wrong, a lot more investment is at stake in a 3-4 mile lateral.

Third is that double lateral length doesn’t double the production rate because of what happens back in that vertical stretch. “Typically, the hole at the top is the same size (as for the shorter lateral). So you have more oil that wants to come out, but you can’t necessarily get double…” in daily production, LeBlanc explained.

 

The Sky’s Not the Limit

Many issues, such as technology and procedures, may continue to advance the length possibilities. But the map is still the map, and that creates certain borders, said LeBlanc.

“Probably the main factor in not going further is that you need contiguous acreage to do so. If your acreage block is only one square mile—well, sorry, you’re only drilling 5,000 feet.” That’s another place where the supermajors have an advantage; their leases are usually much larger.

He noted that this issue is being addressed in some small, under-the-radar swaps where companies may trade a few acres in lease A for a corresponding amount in lease B, so both have more room to stretch their (lateral) legs.

And, while U-shaped laterals may make sense for operators whose acreage footprint is too small for longer wells, LeBlanc sees their future being mostly in the future.

 

Lateral Hot Spots

S&P data show that there are more of the longer laterals on the eastern side of the Permian than on the west. “You’ve flattened out over on the Delaware side at about 10,000 feet, or less than 10,000.”

As to why that might be, LeBlanc mused that “the western side is very, very hard rock, making it a very arduous drilling process. There, you probably want to keep your wells shorter,” to limit the cost of the greater horsepower required to drill long laterals in that zone.

 

Exxon’s SE New Mexico Gambit

In another bit of under-the-radar information, LeBlac observed that ExxonMobil’s push toward longer laterals also involves its investment in the area around Carlsbad, where all surface use is reserved for the area’s rich potash mines. No oil and gas drillers allowed, at least not on the surface.

“[ExxonMobil] need[s] to develop 5-10 mile laterals, or at least 4-5 mile laterals to be able to go under the mines and get a lot of the oil they need,” he said, adding, “They have been some of the leaders in the area and are touting this as a way of saying to their shareholders, ‘We’re going to be able to monetize these wells.’”

 

For Nine, Making It Work Starts with Reliability

Nine Energy Service handles many completion procedures. Nick Pottmeyer is President of Completion Tools Operations for the company, and Joe Huwel is President of Cementing and Coiled Tubing. Both lent their insights into ways Nine is moving forward in accessing longer laterals.

For completion tools, said Pottmeyer, “Reliability became very critical,” especially because “time is of the essence.” Clients are focused on efficiency, but also because lateral lengths are so long, coiled tubing cannot reach TD [total depth] on some of the wells. So, if we have an issue early on, and they can’t get coiled tubing to depth, for a preset plug or whatever it may be, it becomes extremely expensive to remediate.”

Among the improvements, Nine has also developed a pump-down ring to aid in pumping the tool string all the way to the bottom of the well. With longer wells come added friction and drag due to increased deviations and, in some wells, horseshoe laterals, and the pump-down ring helps overcome those challenges.

Attached to the bottom of the frac plug, the rubber ring makes the pump-down more efficient by increasing the outside diameter of the plug. By keeping the fluid from flowing past the plug, the pump down ring harnesses more of the fluid’s force, reducing the total amount of fluid bypassing the plug and reducing the amount of fluid and horsepower required to pump the plug to set depth.

Another new tool is the frac dart, which Pottmeyer described as a “ball recovery feature.” The frac plug, which is used to isolate the stage, requires a frac ball to seal the ID of the plug. The frac ball can be deployed in two different ways. Option one is to pump the ball down on top of the frac plug after wireline has set the plug, perforated, and the toolstring has been pulled from the well. For option one, if the plug is set and the wireline crew is unsuccessful in perforating, they can pull the tool string out of the well and repair it, but as long as the ball is in place, they can no longer pump through the frac plug’s inside diameter (ID) because the ball blocks the path—which normally is its job.

“So [by] having a ball recovery feature,” said Pottmeyer, “you have a way to remove that ball from the seat. You pull out of the well, make changes to the tool string, and pump the tool string back down and perforate.”

 

Cementing the Progress

For Huwel, in moving from vertical to horizontal, then to longer horizontals, “It changed the equipment we had and the slurries that we use.”

For example, cementing units have become more powerful, increasing from 600 hydraulic horsepower 10 years ago to 1,000 or more today. “You need that extra horsepower when you’re displacing these longer laterals, as the friction pressure of the slurries, because there’s more slurry being pumped inside the pipe, so your friction pressures are higher and you’re having to push it even further out.”

Cement slurries have also seen a redesign. In a horizontal well, the slurry must travel a long way to reach its destination, where it is to set up. In long laterals, Huwel explained, the danger has been that the cement may settle out along the way, keeping it from being of any use at its destination and requiring costly remediation. Proper slurry design lets it stay in suspension for the required distance.

The issue with coiled tubing not reaching TD, said Huwel, revolves around how much tubing a single truck can carry. Due to weight and size limitations on the highway, coiled tubing trucks are currently limited to +/- 29,000 feet, which is not enough to reach TD on a 30,000+ foot well.

Another option, joining two coil strings together, is beginning gaining traction, Huwel said, adding that it may become the norm by 2026, as laterals continue to grow past three miles. While that essentially allows tubing strings of much greater lengths, the drawback lies in the amount of time it takes to weld the two together, and the delays it creates in the completion process. It can take anywhere from 4-12 hours to join the two.

Going Up Around the Bend

While there are indeed some additional challenges with horseshoe laterals, Pottmeyer said they have been small compared to lateral length as a whole. “It was not as difficult as we expected it to be,” for completions, he said.

Nine does request a deviations survey, “So we can run a pumpdown analysis. That pumpdown analysis really helps us understand the challenges in deploying the tool string.” Or in retrieving it. The survey helps with both the wireline and drillout.

It’s similar for cementing, said Huwel. He noted that there’s already a bend at the place where the hole turns from vertical to horizontal, which creates friction, so the horseshoe is just one more bend in the road, so to speak.

 

Deepest Longings

Raoul LeBlanc pointed out that lateral lengths expand as technology and procedures first get comfortable with existing lengths, then their purveyors look for ways to get just a little bit further—as long as that “little bit” seems to be in 2,500-foot increments. Where there are indeed limits, the length depends on a combination of lease size and new technology.

 

A longtime contributor to PB Oil and Gas Magazine, Paul Wiseman is an energy industry freelance writer. His email address is fittoprint414@gmail.com