Drilling’s Next Generation of Challenges

Drilling is going off in a lot of directions. At the recent IADC/SPE Drilling Conference in Fort Worth, Texas, technical and panel presentations ranged from the first-ever report on the hottest well ever successfully drilled to tips on translating drilling performance data into numbers that management can appreciate.

It was a younger crowd than past conferences, reflecting the industry’s rapid generational change. Panelists noted that “millennials” bring key skills to the industry for a data-driven age, but have a lot to learn about running a business in this fast-changing sector.

The Industry’s New Generation Adds Skills But Faces Hurdles

The rapid generational change of exploration professionals was accompanied by dire warnings about all the experience lost. But the skill sets that younger workers bring with them could provide the industry with the expertise needed to make a big, belated, technology shift.

“Five years ago, the average age of a geoscientist was 65 years. There was talk of a wave of retirements that would wipe out all the knowledge in this industry. You have not heard that in a couple of years. All those people retiring were not nearly as critical” as thought, said Jim Wicklund, managing director for oilfield services research at Credit Suisse.

The comment was made during a discussion of the future of technology at a panel session during the conference.

Those industry newcomers grew up in a wired world where knowing how to get the most out of software is as common as rebuilding engines was for the generation that came in during the 1980s. The panel discussion was sandwiched in between technical sessions focused on gathering and using real-time data to maximize productivity and strides made in automated drilling.

Young engineers visit the exhibit area at the IADC/SPE Drilling Conference.


“Millennials are not the bottleneck here. A change of generation will radically accelerate technology,” said Karl Blanchard, executive vice president and chief operating officer at Weatherford, adding that, “We in management are the bottleneck. They grew up with the technology.”

They are a promising group with needed skills, but they also have a lot to learn.

As the father of a son who works in the oilfield services business, Blanchard is both proud of his son’s skills and has some blunt fatherly advice about the hard work it takes to sell ideas—such as building a network of supporters and establishing the credibility needed to get a hearing, and possibly a green light.

For Kuhan Chellappah, a drilling fluids specialist for BP, the future of the industry is his waking reality. He is still young, but with more than a decade in the industry he is among a relatively small group of technical experts with that level of experience.

His job demands that he be entrepreneurial, agile, and quick to learn from experts outside the industry, which is not a bad short list of corporate survival skills during a period of rapid change.

Pioneer Resources is consciously working to bring in outside thinking with a technology review program that has featured experts ranging from an astronaut to a mathematician. It runs a program modeled after the television show Shark Tank, offering feedback on ideas, and a corporate fund that has backed $50 million in projects, said Sha-Chelle Manning, director of corporate innovation for Pioneer.

One project being deployed is an automated system for analyzing core samples to help identify prime drilling targets. The system was so good at the job once done only by geoscientists that it led to questions about their future job prospects.

“They will have to do different jobs,” she said. The automated system can generate more information for exploration teams, which will need to find ways to exploit it.

Those looking to get ahead need to combine an understanding of the business with their technical skills.

Occidental Petroleum’s training program for technical people advises them to consider their audience when talking to others. That can go well beyond avoiding technical jargon when speaking to non-engineers, as shown in the third story in this report.

These critical skills are not normally part of the highly technical university engineering curricula. Engineers need more training in everything from supply chain management to applied analytics, Wicklund said. And ideally they could also take a class about “where they get to dream of what energy could be.”

Those who do not learn business skills are likely to feel stymied in the future. “The greatest engineer in the world that does not understand a P&L (profit and loss) statement gets himself pigeonholed” as a technical expert with little upside potential, he said.

It Can Be Hard To Prove You Really Cut Costs

A few years ago, those in the drilling group at Occidental Petroleum were proud of how they had slashed the cost of drilling a well by significantly increasing the number of feet drilled per day.

Then they heard a speech by a former top executive who singled out the measure of drilling speed as a poor one to focus on when the goal is cutting costs.

“That was what we used as our main metric,” said John Willis, drilling and completions manager for Occidental in the Delaware Basin. While his group saw it as a clear sign they were getting more production out of contractors that charge by the day, the “perception at the executive level was [that] we were not interested in the cost.”

The problem was that while drilling more wells means greater production, it also means the total cost of putting those wells into service was higher than expected when the annual budget was created. Rather than trying to convince executives to embrace the metrics used by drillers, they realized a system needed to be created to translate their results to answer questions important to executives, particularly: “How am I doing versus the budget?”

That is actually a tricky question. The difference between blowing the budget and living within it depends on how you define the word “budget.”

Comparing the cost of drilling to the annual budget would have shown costs running 12% over budget, according to an example in the paper SPE 189683.

These charts are based on the same wells drilled. The difference is that the budget is adjusted in the second chart to reflect cost increases as faster drilling has allowed more wells to be drilled. Source: SPE 189683.


But the well costs line up with the budget when using the reporting system Occidental’s drilling team installed 4 years ago. The difference is the system constantly adjusts the budget monthly to reflect the changes in the number and types of wells drilled. The revisions also account for well performance—a broad category covering operational issues such as the amount of material used and the changing cost of the goods.

Everyone’s Problem

It is a large effort for the Occidental drilling team to track all the details required to offer a credible accounting of well costs. The problems it addresses are common throughout the industry.

“In the history of drilling, it is unlikely that any company ever drilled exactly the number and types of wells included in the original budget,” the paper’s authors said.

That is particularly true in drilling-intensive unconventional plays such as the Permian, where the operators like Occidental are constantly working to get more out of the fleets of rigs that are mass-producing wells.

The cost reports condense the results of a complex process so they are instantly understandable to executives, and rigorous enough to persuade an audience wary of misleading measures that can obscure bad news.

That requires a lot of work. They needed realistic cost estimates of the many types of wells with differing depths and lateral lengths, casing, and the fracturing designs. “We have to document all these things,” Willis said.

Drilling engineers have been trained on their cost-reporting role. Accurate field cost tracking based on close attention to detail reduces the risk of a later big cost surprise.

The close attention to detail has helped improve both the drilling group’s operation and how it is perceived.

For example, by tracking the time needed to make pipe connections they were able to significantly reduce the time needed to drill a well, and break down how they had reduced drilling time. They found that constant attention helps maintain productivity gains.

“If you stop tracking rig move times, it goes up. If you track, it goes down and stays down,” Willis said.

While there is a lot of buzz around sophisticated big data analysis, the authors said they have found that the “highest value from continued use year after year has been from relatively straightforward measures.”

And the perception of the drilling division in the executive suites also appears to have improved. Before the changes, significant drilling productivity gains were not mentioned during earnings presentations. Since then, drilling savings have been featured and continue to get mentioned, Willis said.

“Having metrics are not enough; you have to have an urge to improve performance, or the metrics will not mean much,” Willis said, adding, “The longer you use it, the better. It needs to be simple and understandable.”

Engineering Bits for Drilling Down Close to the Magma

One of the hottest wells ever was drilled last year in Iceland, with a bit and mud motor from Baker Hughes, a GE company, surviving temperatures as high as 426°C.

It was the second attempt to drill a really deep geothermal well after the first abruptly ended halfway to its target depth. In fairness to the hardware, it worked right up until it drilled into the magma. It is now displayed in a museum run by HS Orka, the Icelandic power company behind the project.

“We were able to pump water until the magma let it go,” said Ari Stefansson, power plant manager for HS Orka, who was the drilling manager for the project covered in a paper delivered at the conference (SPE 189677).

These roller cones shows wear after drilling through basalt, but the specially designed drill bits stood up to the ultra-hot conditions in a geothermal well. Source: SPE 189677.


The website for the Icelandic Deep Drilling Project said that after the “molten rock was rapidly quenched” there was 20 m of “obsidian glass” at the bottom of the 2100-m hole.

Six years later, a second well was drilled using a specially designed drill bit and motor built to survive temperatures up to 300°C. The rated temperature limit is more than 50% higher than the current maximum for extreme temperature equipment, and double the level for most downhole equipment, said Ralf Duerholt, a technical advisor for BHGE in charge of that work.

The first well showed it is possible to drill down to the lava using available hardware cooled by drilling fluid. But such extreme conditions cause early equipment failures, increasing the cost and time needed for drilling in the hottest depths that can deliver the most energy.

The equipment development was partially paid for by a $10-million grant from the US Department of Energy. It wants to fill a gap in geothermal drilling equipment that has held back development of a potentially huge energy source. The project in Iceland was the first chance to drill with it.

The rock is basalt, a tough, fractured obstacle. For that reason, BHGE built a rotary cone bit for its ability to stand up to the hard rock. That meant more moving parts than a simple PDC bit, which has diamond-tipped cutting teeth and does not require seals or lubrication systems, but presented a greater risk of damage without careful use, Duerholt said.

The reason for trying to get so near the magma and its extreme heat is because that is where the energy is.

By getting to the bottom of a well twice as deep as the typical geothermal well, HS Orka tapped a source of electric power that is 5-10 times greater, Stefansson said. That is enough steam to generate from 220 GWh to 440 GWh of electricity per year from a natural source that is always “on.”

One of the limits of using geothermal has been drilling the number of wells needed, which require reliable data from measurement-while-drilling (MWD) equipment to navigate near the chambers holding molten lava. The driller must also create a pair of nearby horizontal wells, one to inject water into the fractured rock and a second to produce the steam.

The Icelandic project showed that it is possible to build an effective drill bit and a mud motor, which is in a curved casing for turning, and the third well planned for early 2019 will test the MWD equipment, which recently was qualified for drilling. That is a critical piece of the system needed for the directional drilling required to generate the steam needed to drive a power plant.

That temperature specification goes well beyond what is needed in the most extreme oil wells planned, but it could provide more reliable drilling alternatives, said Duerholt.

During the 168 days of drilling, HS Orka worked through a series of drilling obstacles including periods of lost circulation when it encountered large fractures. That added drilling days, but in a well that hot there is a small upside—all the fluid pumped to deal with those ­losses cooled things.

The cooling effect of the fluid flowing from the surface was greater than expected in the second well, holding the temperature to below the 300°C maximum rated level.

Extended periods of extreme heat near the bottom of the nearly 4700‑m well required some big changes. The limit of the elastomers used for seals is around 200°C, so they were replaced by parts machined so precisely they could form metal-to-metal seams. Moving parts were lubricated by grease designed to survive those extreme conditions as well as specially formulated drilling fluids.

There were electronic components made of materials that raised the maximum operating temperature, but the limit was still far short of what was needed. The tool builders isolated the components within an insulated capsule surrounded by a water-filled container that gradually boiled, with the resultant steam going into a second container. The change of state absorbed heat, holding the temperature inside to 175°C or less during the qualification testing.

When in a spot where the temperature is 300°C, the MWD system can stay cool enough to avoid damage for 50 hours. In conditions where the temperature is not so high, it can run longer, Duerholt said. Its commercial future will depend on whether the payoff for longer-lived ­equipment justifies the added cost of making this high-performance equipment.

The longest run for the bit was 467 m. While the heat lessened the effectiveness of the metal-to-metal connections, they performed up to expectations, as did the redesigned lubrication system.

The superheated steam is also acidic, which could corrode pipe but keeping it in a supercritical state should reduce the damage it causes.

Now HS Orka is planning the next well needed to create this huge underground heat exchange system.

For Further Reading

SPE 189677 A 300 Degree Celsius Directional Drilling System by A. Stefansson, R. Duerholt, J. Schroder et al., Baker Hughes.

SPE 189683 Measuring Land Drilling Performance by J.B. Willis and R. Jackson, Occidental Oil & Gas Corp.

Drilling’s Next Generation of Challenges

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

01 May 2018

Volume: 70 | Issue: 5

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