Oilfield services look to 2019 with some firm trends in place. Rig operators are consolidating and standardizing their fleets with premium machines now that day rates are covering the cost of capital. Sand loads, pressures and lateral lengths are all still increasing, but the pace of acceleration is slowing. There is a renewed focus on quality, not just quantity. Even as drilling is standardized, each well is being customized or tuned. Service firms are sanguine about Big Data presenting the next important opportunity for gains in efficiency and productivity.

“In every downturn or correction, we look to the start of the recovery,” said John Lindsay, president and CEO of Helmerich & Payne (H&P). “When things started to improve in 2006, we started building our FlexRig3s and 4s. We continued building about four rigs per month through three subsequent cycles from then through 2014, with the exception of the global recession. As a result, through the mini-cycles, the other drillers were losing share because it was the older rigs that were being laid down.”

To underscore the point, Lindsay cited that H&P had a market share of 4% in 2001, 8% in 2008, 15% in 2014 and 21% in 2018. “Through the cycles we have been able to invest in capabilities. In October 2014 we had 300 rigs operating. By the summer of 2016, we had just 67 rigs turning to the right. That was tough, but it prepared the organization for growth. We put 127 rigs back to work in our fiscal 2017 [which began Oct. 1, 2016] and upgraded 91 rigs to super spec that year. In fiscal 2018 we were on pace to upgrade 48 to 50 rigs. For fiscal 2019 we have 12 more upgrades committed and a further 12 planned per quarter if demand holds,” he said.

To be sure, rig counts are very different from what they were even 10 years ago. The fundamental changes in unconventional development, notably pad drilling, and the fundamental changes in rigs as drillers consolidate around larger and more capable designs have altered the relationship between rig counts and industry activity.

“In the year 2014, the industry had 1,800 to 1,900 rigs running, and we are down to about 1,000 to 1,050 today,” Lindsay said. “In 2014 AC [alternating current] drive had about 40% of the market. Today that is 67% to 70%. And the replacement cycle continues. The consolidation of the industry at the higher-end rigs is a result of the longer and longer laterals as unconventional development evolves. As recently as 2015, the average lateral length we drilled was 6,000 ft. Today our average is 8,000 ft. We have even drilled some for clients at 10 ft, 12 ft and 15,000 ft. That adds complexity and demands on the rig.”

This is not to say that rig counts are not important. It is more a matter of which rig is doing what. “The industry fleet is delivering more wells with longer laterals more quickly with a smaller fleet,” Lindsay said. “For us, a big part of that is not just having an upgraded fleet but a uniform fleet. These are our rigs built to our specifications. We are effectively the original equipment manufacturer, and we also own a lot of the software.”

That software element is important, Lindsay said. “With the emphasis on better well economics in longer laterals, producers are very attentive to enhancing the quality of the wellbore and the placement. That is especially true with infill drilling and tighter spacing. That is where our MOTIVE and MagVAR software come in,” he said.

There are only about 250 legacy mechanical rigs and the silicon-controlled rectifier systems drilling horizontal wells, Lindsay estimated. “A lot of our competition has had to write off a big portion of their fleets. That was a big drive for us to build the modern rigs. When those went to work, we got 90% of our money back on the first contract,” he said.

What counts as a big well or a big fracture also has changed and varies by basin. “We started to see the trends to longer laterals, heavier sand loads and higher pressures as early as 2012. The Eagle Ford shifted more quickly than others, and we had a presence of 80 or 90 rigs in that basin, so we had a front-row seat. It used to be that 5,000 psi was standard for pumps. Today that is 7,500 psi,” he said.

That said, H&P has mostly kept to its knitting. “As our peers got into pressure pumping and other services, we stuck with what we do best. That has enabled us to reduce cycle times. Now [that] the new build cycle is over and the industry is into the upgrade cycle, we will continue to gain share,” Lindsay said.

Full-scale industrialization

The industry has evolved into “the full-scale industrialization of the drilling process,” said Kevin Neveu, president and CEO of Precision Drilling, a land driller that is active in all shale plays across North America. “Pad style drilling and well standardization are driving today’s exceptional performance. And that is not just speed; it is also the quality of the wellbore.”

Neveu is very specific in his description of drilling as “industrial” in contrast to the term “manufacturing,” which is commonly heard around the industry. “In manufacturing you control every variable of the process. You can see and touch the work piece in real time. But in drilling you never actually see the cutting tool or the work face and certainly not in real time. I much prefer the term ‘industrialization.’”

He is also very specific about how the drilling process is being industrialized at the same time well completions are being customized. While the latter is often considered the result of advances in fluid chemistry and pressure pumping, Neveu believes the next level of advances will come from data analytics.

“We have already gotten through most of the gains we are going to get through mechanical process improvement,” he stated. “We are now looking to the data side and have some work to do. Today, we can capture 20 gigabytes of well data per day, but it is difficult to sort through that much or even move those through a central hub. There is a huge opportunity in the data surrounding the wellbore process. We are just scratching the surface,” he added without a hint of irony.

And while the top performance of the best rigs may be testing the physical limits of the process, not all rigs are at that level. “Only about half of the rigs running today are leading edge,” said Neveu, and a “few of those are operating at optimum efficiency.”

These modern rigs are making a remarkable difference. “In the Permian we are able to drill short-lateral wells in 12 days and long reaches in 20 days,” Neveu said. “That is down from 65 to 78 days, a reduction factor of 60% to 75%. We believe the pace of improvement is flattening, but as we get better at interpreting data, we will be able to build the best well every time, eliminate inconsistencies and strive to eliminate downhole failures.”

Specifically, he said Precision is focused on the elimination of human bias and variability. “It is a matter of interpreting what is happening at the drillbit in real time based on advanced analytics,” Neveu said.

As 2018 winds down and he looked ahead to 2019, Neveu believes that business was “improving as activity levels for [Precision Drilling] are about 75% to 80% of where they were at the peak in 2014, while the industry is in the range of 50% to 60%. We have gained share.”

Working out of the worst downturn It is important to note that there is a lag between price cycles and drilling activity of six months to a year. Thus the low point for the price of oil was in the second quarter of 2015, and the low point for rig activity was in the second quarter of 2016. Many long-term newbuild contracts initiated in 2014 may have had several years of duration, some of those date back to November 2014, signed just weeks or even days before the OPEC actions precipitated the price collapse.

“The worst downturn I have ever experienced in a long career was 2015 and 2016,” Neveu recalled. “That was the only time we had two years back to back where producers substantially reduced their capital expenditure [and] demand for our service essentially collapsed. The downcycle in the early ’80s was long and protracted, and peak to trough may have even been greater, but it was over a longer time frame.”

Through all recent cycles, there has not been a great deal of consolidation in the drilling sector. One reason has been the myriad rig types that make it difficult to integrate fleets. The availability of capital to finance a deal also has been rare. So the bid that Precision has made for Trinidad Drilling is a unique opportunity to “take us from No. 4 to a solid No. 3 in terms of market share in the U.S. The Trinidad AC rigs are a rare fit for compatibility rather than the start of a roll up as standardization of the rig fleet remains a strategic focus for Precision.

“The Trinidad board supports the deal, and we hope to close the deal by the end of 2018,” Neveu said, “with an expanded fleet that would include about 170 similar high-performance, AC-drive pad-capable rigs.”

“Generally, as prices improve so does activity, but that varies greatly by basin and from oil to gas,” said Michael Henry, global operations manager for production enhancement at Halliburton. “There are some pipeline constraints in the Permian and also in the Northeast. That has forced operators to develop other parts of their holdings until the constrained areas can get additional transportation.”

He also noted that there seems to be an increase in drilled but uncompleted wells (DUCs), but that may be temporary. “Operators are being more disciplined with their budgets as we get close to the end of the year,” Henry said. “In previous cycles they may have just gone ahead and spent the money to complete, but today producers are keeping to the idea of the most production for the least money.”

That sort of discipline also leads to flexibility. In the 2014-2016 downcycle, many producers accumulated DUCs because they had to. When the recovery started, everyone was happy to go DUC hunting. Having now established that completion does not have to come immediately after drilling, producers have that as a new option for deploying their development dollars and sticking to budgets. That not only keeps shareholders happy but allows tweaking of production to meet pricing and demand variations.

Deeper downhole data

Another manifestation of that separation between drilling and completion is that as drilling has become more like a manufacturing process, completion is trending toward customization.

There is no contraction between repeatability and custom tailoring, Henry said. “They are not mutually exclusive. A streamlined, integrated approach to more wells per pad is just efficient use of equipment and capital. Operators do want to know about well dynamics, placement of course, but also fracture modeling and potential impact on other bores,” he said.

As one example, Henry noted that the cost of fiber-optic, in-bore diagnostics has become much more economical. “It’s not quite mainstream yet, but it is becoming much more common,” he said. The cost is not the only thing that has been brought down; processing times have been reduced as well.

What constitutes a big fracture is changing as well. It used to be that 10 by 10—10,000 ft deep and a 10,000-ft lateral—was considered a big well. “That is certainly not standard,” Henry said, “but it’s not considered very big or long as it used to be. We are seeing more sand and more stages [and] 500,000 to 600,000 pounds of sand per stage is still considered big. We have done some very big jobs with 1 million or 2 million pounds per stage, but those were unusual, high-intensity jobs for very specific formations.”

As the pace of the recovery in domestic production accelerates, so do most of the characteristics of wells. “In the Midland Basin, laterals are moving rapidly toward 10,000 ft as a standard,” said Dan Fu, director of technology at BJ Services. “Just last year the average lateral length was 8,000 ft. Today it is 9,500 ft. Half of the wells are longer than 2 miles.”

He also observed that while wells are getting longer, rigs are drilling those wells in the same amount of time. If anything, spud-to-total-depth and spudto- spud times are dropping on aggregate. Once the bore is finished, volumes of proppant used also are growing. “We have seen an increase of 30% to 40% in proppant loads,” Fu said. “In 2014-15 the average was 1,500 pounds of proppant per foot; now that is up to 2,500 pounds per foot.”

With all that increased size and performance, costs are actually lower. “In the past few years, the costs of drilling and completing have decreased by $5 to $10 per barrel,” Fu said. “That is a result of a combination of factors. More wells are being completed faster and more efficiently, so the cost per barrel is going down.”

That said, no tree grows to the sky. “As spudto- TD [total depth] and spud-to-spud times are decreasing, and as we put more wells on a pad, we have to manage the wells and each bore carefully for possible interference,” Fu said. “There is a growing industry concern about the parent-child relationship for each well on a pad. Well-to-well separations are down to 1,000 ft or even 800 ft. With current fracking techniques and pressures, fractures extend as much as 400 or even 500 ft from the bore.”

Thinking and planning in 3-D

Thinking and planning in 3-D are starting to get as close as possible without the risk of communication. “There is a lot of experimentation,” Fu said. “We have done hundreds or thousands of wells, so we don’t take a lot of measurements now. The focus is more on trying to optimize. Companies are understanding the resource better using advanced analytics. Data analytics is becoming very attractive from the cost point of view.”

Fu added that producers and drillers are starting to think in terms of cubes, which is to say all three dimensions. “This is all very new, just over the horizon. People are starting to think in full 3-D on how to complete stacked pays at multiple depths and multiple directions with multiple bores at the same time.”

BJ Services is an independent pressure pumping company that was created when CSL Capital Management and West Street Energy Partners (WSEP) acquired the North American land cementing and hydraulic fracturing businesses from Baker Hughes, a GE company (BHGE). CSL and WSEP have a 53.3% stake, and the combined companies of BHGE have 46.7%.

BJ Services organizes its R&D into three segments: chemistry, data and equipment. “We don’t try to do everything in house,” Fu said. “We work with chemical suppliers, data analysts and equipment companies. Our ThinFrac MP tunable chemistry incorporates several properties including proppant transport and precision breaking. We use that in about half our fleet and have seen improvements in cost to operators.”

Vast new computing power at relatively low cost and high speed, so-called data mining or Big Data, has put new emphasis on public or industry data in addition to the proprietary data that a service company gets from each job.

“We are looking at public data as well as our own to help determine how different reservoirs respond,” Fu said. “We are working with a small data company on simulations in lieu of running a tool into the well. That system, which we call SAVANT, is faster and there is less risk of a mechanical problem such as a tool getting snagged. We consider this reservoir characterization a differentiator for us.”

One essential factor in faster drilling and completion is a modern high-horsepower flexible rig.

“Legacy equipment is just not up to today’s jobs,” Fu said. “Now that we have evolved to what amounts to a manufacturing process, the reliability of the equipment, in addition to its power and flexibility, is essential.”

Against the grains

Sand supply, especially from local sources, has gone from tight to almost oversupplied in just a few months. “In the Permian, as well as South and East Texas, most operators are willing to use local sand,” Halliburton’s Henry said. “It is too early to tell the long-term results as compared to using Northern white sand. There have not been any initial concerns, no short-term impacts that I know of. But [for] long-term [impacts], the jury is still out.”

That sudden swing in sand supply from tight to loose is a microcosm of the logistics and service sector broadly. “It has certainly been a challenge for the industry to go from the slowdown to a fast ramp-up,” Henry said. “We have certainly learned to operate more efficiently. Part of the acceleration is that information flows more quickly so people are making more quick decisions. Some service companies have been more successful than others in adapting to that pace.”

While rigs have been consolidated to a largely standardized fleet of big, powerful and flexible models, the evolution of proppant has been one of diversification. “The industry has moved quickly from ceramics to sand,” Fu said. “We are now seeing the evolution from primarily use of Northern white to in-basin sand. Northern white is still used, and I expect will continue to be. The percentage of in-basin sand is likely to grow to more than half.”

While the mix continues to shift, loads are starting to settle into a range. “We have about reached a plateau in sand volume,” Fu said. “Not too long ago we would use 30 [million] to 40 million pounds per job. Now that is 200 million and climbing, but not climbing as fast.” Specifically he was referring to BJ Services’ new blender, which is able to handle more than 200 MMlb of sand without failure as compared to 30 MMlb to 40 MMlb in the previous design.

“Within that load, we are using a combination of very fine 100 mesh and coarser 40/70. We have heard of some experiments with 200 mesh, but that trend to finer grains has stopped,” he said.

Mammoth Energy touches just about every basin across its service lines. “We see stable activity across the three main areas of the country: the Northeast, Appalachia and the Utica; the Scoop and Stack; and the Permian,” said Don Crist, director of investor relations. “Things are up a bit in the Eagle Ford in the last three months [as of third-quarter 2018], but the biggest change has been in the Rockies. We have been getting a lot more inquiries from the Powder River Basin and the D-J [Denver-Julesburg].”

For all the attention that the Permian gets, Crist noted that it is actually a late adopter in terms of drilling and completion techniques. “The Marcellus- Utica, the Scoop and Stack, even the Haynesville and D-J have all been early adopters in the past,” he said.

As an example, Crist said that “all the jobs we have done this year, we have used 100 mesh initially to sandblast the formation, then 40/70 behind that as proppant to hold the fractures open. This has shifted in recent years as historically 100% 40/70 was used. Operators are seeing the benefit of using 100 mesh to start fracks and open up the formations.”

Mammoth has expanded two of its facilities over the past year or so. The mine at Taylor, Wis., was expanded from 700,000 tons/year to 1.75 MMtons/ year. A new 300,000-tons/year dryer was installed in the Piranha facility and also in Wisconsin, increasing the capacity of that mine to 1.9 MMtons/year.

Quality over quantity

“We feel strongly that sand is specific to a need. Some operators have tried to use 100 mesh for completions, and long-term production is impacted when compared to using 40/70 as a propping agent. As a result, we have seen completions standardize with approximately 25% 100 mesh and 75% 40/70.

“While acknowledging the cost advantage of in-basin sand,” Crist added, “Northern white will have a place in the market because it is simply a better sand.”

Regardless of grain size, he noted that loading seems to be stabilizing around 3,000 lb/ft. That is substantially higher than the 1,000 lb/ft that was common just a few years ago.

Pressures remain variable, mostly by formation. “Here in Oklahoma, the Scoop is deeper and is a higher pressure formation,” Crist said. “The Stack runs across several zones. In the northeast portion in Osage County, pumping is usually at about 6,000 psi. In the deepest part of the Scoop, it might be twice that. From an equipment standpoint, anything above 8,000 psi is high-pressure work.”

Laterals are also variable. “About 6,500 ft to 7,500 ft is standard,” Crist said. “[And] 10,000 ft is still big in most places, but in the Bakken we have been doing 10,000 ft for eight years. In the Permian we are seeing an average of about 7,000 ft with some wells getting longer toward 10,000 ft.”

By the end of the year, specialty chemicals firm ChemTerra Innovation expects to have its greenfield chemical blending plant in service in West Texas. ChemTerra is playing both sides of the proppant business, supplying coatings that reduce dust and other lost material to rail cars of premium sand that are shipped from upper midwestern states and also supplying coatings for in-basin sand to improve its performance to compete with Northern white sand.

ChemTerra was created as a discrete operation within Trican Well Service at the end of 2017 to sustain the North American growth of its oilfield chemicals business even as the parent well service business consolidated to exclusively Canadian operations. ChemTerra also has developed surfactants to enhance oil recovery, part of its larger portfolio of oilfield chemicals for hydraulic fracturing, well stimulation and cementing. The company manufactures some of its own coatings and chemicals and also contracts some manufacturing to toll blending companies.

“We are still a new company just establishing our place in the industry,” said Natasha Kostenuk, ChemTerra’s general manager, “but we have been very well received and [are] looking [for ward] to a strong 2019.” She added that business in Canada has been a little tough lately with all the pipeline controversies and export constraints, so the company has been focusing its chemicals growth in the U.S. where production and exports are booming.

“We rolled out the proppant coatings in Canada through Trican,” said Bill O’Neil, ChemTerra’s R&D director, “and now the push has been in the U.S. Business is very different on the other side of the border. Within that overall growth has been the major shift to local sand in the Southwest. The quality is very questionable for in-basin sand, but the focus has been on cost rather than performance.”

About three-quarters of the delivered cost of Northern white sand to West Texas is transportation. That cost, plus the challenges of supply as demand boomed, led to the focus on local sand. “We are already starting to hear about problems with fines washing out valves during flowback,” O’Neil said. “We have seen samples that are unwashed and unsieved.”

Local sand is “a cheap and quick solution,” O’Neil added. “Some operators might not be bothered, until they start to see damage to equipment on flowback.” The overall approach for the coatings is in three areas: dust control, consolidation to prevent loss to flowback and improved crush strength.

Going with the flow

Water will continue to be an area of focus, added Halliburton’s Henry. “Sometimes it is top of mind, sometimes a little lower, but never not a factor. The driving factor is cost, both to procure water and to dispose of it. Fracturing is about flowback. Wherever possible, operators will use produced water. Of course that changes the chemistry so it becomes a challenge for each well to check compatibility with both the characteristics of the water and of the formation. That gets back to the customization idea. When using produced water, the most important thing is to pay attention to the source,” he said.

Water remains variable, not so much with the basin per se, but more with the amount of activity in the local area, explained BJ Services’ Fu. Lots of activity in the immediate vicinity means more demands on water sources and also more produced water, so the strong tendency is to use what is most readily available and less expensive. “Producers are definitely favoring use of produced water,” Fu said. “That is a trend in every single basin. We are even starting to see this in the project requirements.”

Fu stressed that decisions on water should not be made in a vacuum. “In general, cations in produced water can reduce the efficiency of regular friction reducers by 70% to 80%. We use specialty friction reducers to address that. It all comes down to economics. There are lots of options for producers from water sources to chemicals to equipment and techniques. Fracturing fluids are indeed truly tunable. It all comes down to costs on how much to tune,” he said.

Trends in chemistry seem to mirror trends in sand. “As a chemical company, we see people pushing more and more to produced water,” Kostenuk said. And that makes for highly variable water characteristics, “but with all the pressures on costs, there is also pressure on chemistry. There is a general trend when costs are under pressure for people to water down the chemicals. But there is a need to maintain quality and performance.”

One example of that is an additive that enhances oil recovery from the start. “EOR is usually considered secondary or tertiary recovery,” O’Neil said, “but we have published papers and received patents for chemistry that turns frack water into the equivalent of a waterflood.”

Across the industry in aggregate, O’Neil estimated that water use is about 50:50 fresh to recycled. “The trend is definitely going more to recycled, but even in a closed system there is some loss that has to be replaced. Canada is still using mostly freshwater, but even that is starting to change,” he said.

Getting that water and sand downhole is also in flux. “We are hitting the point where pressure pumping is tipping into oversupply. The pumpers have built up their horsepower, perhaps too much. They are seeing the same price pressure as we are seeing in chemicals. The sector never fully recovered from the big recession, and now we are back to pricing pressure,” he said.

Read E&P magazine's other two technology articles, which appeared in the December 2018 "Unconventional Yearbook" issue:

Technology Rules in the Oil Patch

Transformation Continues for Delaware Basin Operator