It’s possible that companies that provide drilling and measurement services have gotten too good at their own game. They’re enabling their customers to find more oil with fewer wells, meaning, potentially, less work for them. And always the push is the same — spend less time drilling and find us more pay while you’re at it.

For Mike Williams, global sales manager for Drilling & Measurements with Schlumberger, the

Figure 1. Powerdrive x5 RSS is a fully rotating system which has helped revolutionize the drilling process. (Images courtesy of Schlumberger)
days when the service company was called on to drill a well by following a line to the target are rapidly dwindling. “The way they judged us was by whether or not we followed the line, and what our mean time between failure (MTBF) was,” Williams said. “It was a very traditional client/vendor relationship.”

In this model, reliability was key. Greater MTBF meant less time tripping out of the hole, which meant cost savings for the client.

While some clients still prefer this model, Williams said the industry is in the midst of a major shift that started about five years ago. “What they really want is to drill the well as efficiently as possible,” he said. “It’s not just how reliable the equipment is but how efficiently the well is drilled. They still want us to put the well bore in the right place, but the right place has changed.” He added that in the past the “right place” was wherever the client thought there might be oil or gas. Today the right place involves maximizing as much reservoir contact as possible.

“Today their expectation is this: Here’s the reservoir section we have. We want you to position the well bore along the reservoir section in the best possible position at each instant along that well bore.” This has a double pay-off for the client — assuming the service company “follows the line,” the well can be drilled more efficiently, and it also maximizes production.

Rotary steerables
This evolution has partially come about because of the increased use of rotary steerable systems (RSS), Williams said. “Originally these systems were used to drill wells that were impossible with conventional motors,” he said. “But that’s a ‘gimme’ now.”

Clients like the fact that an RSS can drill more efficiently than a sliding drillstring. Williams said that tools like the company’s PowerDrive family of RSS rotate everything exposed to the well bore, reducing friction and improving penetration rates by as much as 100%. He added that companies like his are helping clients drill millions of feet per year, and more than 25% is done with RSS. He expects that number to approach 70% within the next five years.
And while the complexity of an RSS reduces MTBF, the efficiency gains more than outweigh the potential reliability decrease.

With this new technology available, operators have begun to think very differently about their drilling programs.

“What does a rotary steerable do?” Williams asked. “It allows us to drill almost any profile a client can think of. Things that were impossible are now possible.

“This whole thing is about efficiency, and efficiency is reliability, but it’s also about the best use of the time you have in the hole to drill as quickly as you can.”

Other benefits include better hole quality, which aids in everything from wireline logs to casing to cementing, he said.

Of course, the main benefit is the ability to place the well bore strategically to obtain maximum drainage. “Any drilling down to the reservoir is a cost — there’s no benefit to the client,” Williams said. “So we drill to the top of the reservoir as quickly as we can. In the reservoir we’re still looking for efficient drilling, but it becomes almost secondary to positioning the reservoir section in the right place.”

In the past this was a geometric profile — drillers looked at seismic and offset well data and drilled a geometric line based on that data. Logging-while-drilling (LWD) has helped change this mindset. But Williams said that until recently even LWD was a reactive technology — even though the formation evaluation data was critical, the fact that the tool was placed dozens of feet behind the drill bit prevented it from being used to make proactive decisions about wellbore placement.

While it’s impossible to place an LWD tool in front of the drill bit, it is possible to enable it to see in front of the drill bit. This has been done by increasing the tools’ depth of investigation.
The company’s PeriScope bed boundary mapper service, for instance, has the ability to look for bed boundaries away from the immediate vicinity of the well bore. “Depending on the conditions, we can see more than 20+ ft (6+ m) out from the well bore,” Williams said. “It means that now you can start to compare where you are to what’s above you and below you.”

The depth of investigation plus the directionality give operators the ability to change their wellpath plan on the fly as new information from the service gives greater understanding of the reservoir. The result is greater exposure to the productive interval — now greater than 90% in many cases.

The drivers
High commodity prices play a part, of course, but in addition Williams mentioned other drivers
Figure 2. PeriScope bed boundary mapper identifies boundaries up to 21 ft (7 m) from the borehole.
that are spearheading this new relationship. Primarily, it’s the fact that “easy oil” is no longer available in most developed parts of the world. This has led to a focus on deepwater developments and extended-reach drilling (ERD), a necessity when trying to tap reserves where a drilling pad cannot be placed directly over the reservoir due to geographic, environmental or economic concerns.

“If you look at the rigs you need to drill in deep water, they are the highest cost rigs in the world,” he said. “You need to drill efficiently, and you need specialist equipment in terms of pressure ratings and getting signal back to the surface.” RSS are a huge part of this equation, he added; systems like PeriScope are less in demand in the deepwater equation today as the challenge has been simply to get to the reservoirs, not to geosteer within them. This is changing, and active geosteering in deepwater wells will come, but today just reaching the reservoir is still a huge challenge. In ERD wells, the opposite is true — the rigs are much less expensive, but the well bores are very long. “You might be drilling 30,000 ft (9,150 m) in a single well,” he said. “Most of it is at a very high angle. So drilling efficiency is very important.”

Positioning is also key. While the main challenge in deep water is just to get to the target from the surface, ERD wells have to be positioned almost perfectly because it takes a long time to access the reserves, and they’re often too marginal to justify a separate drilling and production facility.

Current limitations
Even though breakthroughs in efficiency are opening new doorways for operators, challenges remain. Regarding RSS, said Williams, requirements for high dogleg severity (>10 degrees per 100 ft or 30.5 m) are still a barrier when going from vertical to horizontal. Drilling wells requiring rapid directional changes affects many aspects of the drilling and completion process, including casing and completion tools as well as the running of wireline tools.
He added that these issues typically arise in standard land markets around the world, not in deepwater or ERD situations. “If we had an RSS that addressed the high dogleg rate of change issue, then it would be a technology in high demand,” he said.

Improving the speed of an RSS would help as well. Although they’re already considerably faster than slide drilling, more increases in rate of penetration would further improve efficiency.

“If we could drill faster with more doglegs, a whole new world would open up,” he said.
LWD tools are still mostly limited by depth of investigation, despite the strides that have been made in the past couple of years. This is an evolutionary change that is likely to see continued improvements over time. Primarily, Williams said, clients would truly like to see in front of the drill bit, even 100 ft (30.5 m) out.

“Is that doable today?” he asked. “No. Could it be in the future? Maybe.”

Clients also crave a pressure-while-drilling tool that determines not only formation pressure as the well is drilled but also the nature of the fluids in the formation and a sample to examine at the surface. This can be done today on wireline but not in a while-drilling mode.
So at what point do service companies become so efficient that their clients no longer need them? Williams doesn’t see that coming any time soon.

“There has been a big philosophical debate over whether or not this is a good thing for the service industry because we’re drilling ourselves out of business,” he said. “It may not seem smart, but it actually is because it drives the industry to look at the other opportunities that are out there that weren’t economic in the past but now have become economic. This is partly due to the big increase in oil price, but it’s also because the risk incurred from taking a long time to drill to the target or not getting the production expected has been minimized.”

Additionally, service companies are beginning to enjoy the prestige that comes with being the experts in their field. “Schlumberger drilled 30 million ft (9.2 million m) last year, and I doubt that very many operators, if any, have drilled that much footage,” he said. “The operators are leveraging the experience of the service companies to do new things. It’s always going to be a client/vendor relationship, but it’s also becoming more of a partnership.
“Why hire somebody like Schlumberger or our competitors if the clients can do it themselves? They’re paying for our expertise and global experience to drill more efficiently and to position the well bore in the productive zone more accurately.”