Oil and gas technology mavens see a unique opportunity in the current industry slowdown. Speaking in March at the DUG Rockies event in Denver, Baker Hughes Inc. vice president of integrated technology H.C. Freitag said thousands of drilled but uncompleted (DUC) wells in the U.S. are a ready-made laboratory for the next leap in shale drilling and completion know-how.

New methods of drilling and completing shale wells can significantly improve EURs. “We need to see what else is possible,” Freitag said. “We have a large inventory of DUCs that we can trial new technology in.”

Despite periods of low commodity prices over the past three decades, the industry has been able to increase global proved reserves of oil and gas by 56% and 58% respectively, he said. Technology is the engine behind these achievements.

Baker Hughes Inc. vice president of integrated technology H.C. Freitag said, “Let’s see what we can do to get past the 6% to 8% recovery factor of today, which I think is quite unacceptable.”

More than just advancement of the North American industry is at stake as U.S. producers try out new well rejuvenation and drilling and completion methods. Other countries are relying on the U.S. shale experience to help them crack the code on their domestic resources. “They are looking to North America for insight and experience,” Freitag said. “Right now is the time to be looking at where we should be going, at understanding reservoirs, and what we should be experimenting with to get ready for when prices pick up.”

Spending on U.S. unconventional resource development dipped in 2014 and then tumbled as commodity prices fell. In the meantime, “here we are, still producing at $30/bbl [in early March], and not quite giving up,” Freitag said. North American production is only now beginning to decline. “The unconventionals have been more resilient than anyone imagined.”

At the end of 2014, $70/bbl was considered the average breakeven cost across U.S. shale basins. “Now, a lot of fields in North America are still profitable at $30/bbl,” he said. “Yes, service companies have been flexible in helping operators address costs reduction, but this is not sustainable for a long period of time, because technology must be developed and is costly.”

Newer technologies may help operators efficiently and cost-effectively extract more shale resources with DUCs as the testing grounds, Freitag said. “People used to say the days of easy oil are over; that’s quite wrong. It never was easy. It just appeared easy looking back.”

Instead, he said, the days of easy oil may be now. “We have all these wells in place. Let’s see what we can do to get past the 6% to 8% recovery factor of today, which I think is quite unacceptable,” he said.

The industry must return to basics and analyze available data, he said. Big data can be used to develop technologies for source rock reservoirs as opposed to conventional reservoirs but not without considering the economics involved.

“We have to use whatever helps us understand the formation, but technology has to pass the economics test,” he said.

“Yes, data acquisition on each and every well may be helpful, but it has to be economically and scientifically viable.”

The average time spent as a DUC has lengthened for Appalachian and Permian wells through first-half 2016.

Jack Wiener, chief technical advisor with Halliburton Co., said the company is “prepared to go out and complete wells and provide resources quickly” when the time is right.

As part of its effort to understand, model and predict the performance of unconventional assets, the industry should determine what an ideal unconventional well looks like in construction, stimulation, costs, recovery and more. Supercomputing, geomechanics and fluid dynamics all play a role. Freitag discussed frack propagation modeling where high-density fracking has helped double cumulative production versus conventional techniques. Refracturing and restimulation techniques have also made great strides and offer promise in boosting EURs.

“We are at the beginning of a new oil age and at the end of the first oil age,” he said. “We’re now talking about unconventionals and the huge potential they hold for supplying the world with energy.”

Rockies DUCs

Building up a DUCs inventory has been a useful coping strategy for Rockies operators in trying times, said panelists at the Denver event. Uncompleted wells offer flexibility in completion timing, shelf-life and business planning.

“The DUC inventory really allows us a menu of options,” said Heath Mireles, vice president of resource development for Continental Resources Inc.

DUC development gained steam as oil prices collapsed and some long-term contracts with service providers required operators to keep drilling. Continental currently has four rigs under contract in the Bakken, Mireles said.

Jack Wiener, chief technical advisor with Halliburton Co., estimated that about 10%, or 400 to 500 of the approximately 4,000 horizontal wells drilled in the D-J Basin over the last five years, are uncompleted.

Panelist Garrett Frazier, director of Magnum Oil Tools International Ltd., put the total DUC count in the Bakken and D-J Basin at 500 to 600 but said the lag of four to six months in completion data made estimates difficult.

At the time of DUG Rockies, Continental had 140 to 150 DUCs in the Bakken/Three Forks plays, Mireles said. “By year-end, our estimations are we’re going to have 195.” Discussing DUCs’ optionality, he said that an operator “could be looking to maximize production, maximize cash flow or minimize capital exposure.” For now, Continental’s plan “is to maximize cash flow and the rate of return on projects.”

By contrast, Enerplus Resources Corp. has just five to 15 DUCs at any one time, according to Nathan Fisher, vice president of U.S. development and geosciences. Enerplus doesn’t plan on significantly growing its DUC inventory in 2016, although it will likely drill more wells than it completes to limit the risk of “putting capital into the ground that we wouldn’t be completing,” Fisher said.

While the industry turnaround is likely to be deferred until 2017, the panelists weren’t concerned about DUC shelf-life. So far, they’ve seen no threats to the wells’ potential productivity. “We had some DUCs out there for over a year and brought them on with phenomenal results,” Fisher said.

Enerplus doesn’t think downhole formation damage from DUCs is a primary consideration, aside from one possible issue: Offset depletion could affect the efficiency of fracking if wells are left uncompleted for years, Fisher noted.

It can be difficult to determine the optimum time to stimulate DUCs. Fisher believes there is no exact price threshold. Over the past two years, “as costs have come down so dramatically, the prices that we need for economic returns also have changed dramatically,” he said. Forty dollars is the number “where things start to get more interesting.”

Once that point is reached, and companies commit to resuming activity, it will take time to staff up, Mireles said. “There will be a lag time with getting crews back up there and to re-establish the efficiencies that were in place before the slowdown.” Wiener said employment reductions have spurred more disciplined, intelligent performance across the industry. “With fewer people, fewer resources, we have been required to become more efficient,” he said. Enhanced multitasking, necessitated by the downturn, has led to superior management. “We are positioned right now, believe it or not, to react to changes in commodity prices.”

Halliburton is “prepared to go out and complete wells and provide resources quickly” when the time comes, he said.

Not that there aren’t challenges. If operators drill parent wells and return a year or two years later to fill in the pads, “there are real challenges in the Niobrara in regards to pressure depletion,” Wiener said. Daughter wells must be staged carefully and parent wells protected.

Equipment is another area of concern. “You can’t keep a rainy day stock for when all those DUCs start getting ready to go,” Frazier said. “We’re trying to stay in business as well.”

Proppant choice and loading will require careful planning once completions resume. Many operators favor slickwater fracks in order to reduce costs and because they generally perform better early in a well’s lifecyle, Wiener said. Hybrid fracks, however, yield higher EURs, especially in the D-J Basin.

“People aren’t looking at 30 years; they’re looking at the first five years of production,” Wiener said. “We are beginning to see a cross-over between production decline rates of slickwater fluids and hybrid fluids after a few years of production.”

Although slickwaters have good flush production early, “they start to have a somewhat faster production decline rate over time when compared to hybrids, as hybrid fluids are designed for greater conductivity and effective proppant-pack distributions in the reservoir with longer-term, sustained production levels,” he said.

Operators don’t get the same load recovery as with hybrids, and the remaining fluid can alter the formation saturation, damaging the formation by changing wettability and relative permeability and possibly impacting production, he added.

The topic of high-intensity completions elicited some disagreement. Continental finds greater proppant loading to be an attractive proposition in terms of well performance, with data analytics providing additional insight, Mireles said. The initial instinct when measuring proppant loading versus performance is to do a linear regression, he said, but the line doesn’t “go up and to the right forever.” Continental’s tactic is to “jump out and try to cross that line,” discovering how much is too much and pulling back quickly at the point of diminishing returns, he said.

The company has broken the Bakken up into roughly 65 different domains. While “bigger [higher-intensity fracks], for the most part, have been better,” Mireles said, each domain has a tailored completion design.

Wiener warned of the dangers with large proppant volumes and excessive cross-communication within a 16- to 24-well pad. “In the Niobrara, large proppant volumes tend to have a negative effect on the adjacent wells due to excessive well-bashing” and can degrade production on a pad up to 40%, he said. Large proppant jobs are more suited to “the better portion of the Niobrara,” he added. “It’s more bang for the buck in the best rock.”

Regarding density and stage sizes, “The right completion at the right spacing is a thing we talk about a lot at Continental,” Mireles said. “1,320 feet apart versus 660 feet apart might be completely different.”

Tight spacing generally results in a lot of bashing in the D-J and in the Bakken, he said. But bashing can be “a tremendously good thing … it’s almost like refracking from the outside,” greatly enhancing performance. Fisher agreed: “You frack near an offset well, and it doesn’t do anything but good things for the offset well.”

Wiener was more cautious: “In the Niobrara, when you bash the parent wells, more commonly they tend not to come back to the pre-bash level,” he said.

Left: Heath Mireles, vice president of resource development for Continental Resources Inc., said the company plans to use its DUCs to “maximize cash flow and the rate of return on projects.” Right: Enerplus Resources Corp.’s vice president of U.S. development and geosciences, Nathan Fisher, above, said that while it's hard to gauge the right time to start stimulating DUCs, $40/bbl is where "things start to get more interesting."

Cost control

At a Hart Energy breakfast seminar on refracks in late April, DUCs and technology innovation were again touted as integral to producers’ efforts to live to fight another day. As Jessica Pair, upstream manager for Stratas Advisors, pointed out, operators are in survival mode. “While waiting for prices to rebound, controlling costs is the name of the game,” she said.

“In 2014, additional DUC inventory averaged 1,127 in the major basins,” said Pair. “In 2015, that average increased to approximately 2,219, up 97%.” The U.S. added 1,830 new DUCs in its inventory between fourth-quarter 2015 and first-quarter 2016.

“Since early 2012, the profile of DUCs has changed drastically,” Pair said. For example, throughout 2012, wells did not remain a ‘DUC’ for long, averaging 60 days uncompleted. “In 2013 and 2014, we noticed a stabilization of wells where the average amount of days hovered at 95,” she added. Between fourth-quarter 2014 and first-quarter 2015, the average amount of time that a well spent uncompleted increased by 9%. By year-end 2015, this average had increased to 51%.

Pair also discussed the two main types of proppant dominant in the industry since 2012: Raw sand and resin-coated sand. “In 2014, when prices began to become depressed, the industry saw a greater push toward raw sand usage and less toward other options,” she said.

Slickwater fracturing has increased since 2012 due to its ability to help cut costs, according to Pair. “However, multiple operators have also attributed higher IP rates and shallower declines to the use of slickwater fracks.”

Crosslink fracturing was popular in the industry for oil or liquids-rich wells from 2012 to 2014 but has been decreasing since 2015.

Producers will focus their technology expertise on the best acreage and wells in this environment, Pair said. “When comparing the top 20% of wells within top basins, we believe operators can make decent returns around $30 to $40/bbl.” While many wells do not fit this profile, “operators have made shifts to focus on top-tier acreage and will be high-grading new wells to these areas.”

Refracking

Refracking is another technology that may be honed in the downturn. But for now, it’s on simmer for most producers. A panel of experts from Baker Hughes, Weatherford, Fracknowledge and Eventure Global Technology agreed that the technique has benefits, and DUCs offer the opportunity to test concepts. However, low commodity prices have put refracturing programs in the Haynesville and Barnett on hold.

“We’re in a pricing environment where there is yet one more round of layoffs. Who’s going to go take risks like that?” asked Tim Leshchy­shyn, president of Fracknowledge. “But if you actually look at the statistics [of refracks], it’s amazing.”

Stratas Advisors expects prices to steadily rise from mid-2016 onward.

Refracks account for less than 25% of the original drilling and completion costs of wells, according to Leshchyshyn. They cost about $1 million compared to $6 million to $7 million to drill a new well. Given oil prices at about half the price the industry would like, there is a 100% return on investment via refracks, with a quarter of the cost at one half of the return, he added. “But, the return on investment is sometimes 400%. This is above the incremental reserves. This is above net present value.”

Harsh Chowdhary, engineering manager for Eventure Global Technology, referred to a 2009 refrack job involving three wells from the same pad. Two wells used a chemical diverter and one used expandable lining. “When the refrack was done, the mechanical isolation well showed 40% higher production rates than the chemical diverter,” he said. “It is more costly than the other options, but I think that experimentation and R&D are going to drive the technology.”

Leshchyshyn called the economics of refracking outstanding and said that the technology is more successful than not. But “it’s unknown and a little uncomfortable for us,” especially in this low-price environment, he said.

Refracking of horizontal wells is in the early stages, said Baker Hughes’ Freitag. When companies take a “Hail Mary, or pump and pray” approach, the results have been disappointing, he said. Diagnostics are essential. Once unproduced hydrocarbons have been found, the targeted zone can be stimulated, he said. Currently, the industry is using straddle tools to properly stimulate or restimulate zones that were previously bypassed.

“A lot of this technology is being used as we speak,” he added. “The marriage of science and research and engineering to the pressure-pumping schedules is going to make this happen. It’s still in its infancy. I think there is still a lot of work that has to happen before the second wave of the unconventionals.”

Rapid decline rate wells or wells that never produced properly could be refrack candidates.

For Rob Fulks, director of completions optimization at Weatherford, candidate selection could involve using a grid with wells that are stars and cash cows, looking at reservoir, completion and wellbore qualities along with production history. The candidates fall to one area of the grid. Then, further data analysis is done. However, all candidates aren’t necessarily chosen. “You go after the wells that have the lowest risks,” he said.

As for the methods, diversion, chemical isolation and straddling all work. But some methods work better in some basins while only one option may be suitable in others.

“If you have a cemented liner system, which is predominant in the U.S., mechanical isolations are a lot better method to use,” Leshchyshyn said.

“In some basins where you have an openhole packer system behind the liner, those systems can be mechanically isolated but past those perfs … you are left with possibly diverters.” M

Velda Addison, Annie Gallay, Susan Klann and Mike Madere contributed to this article.

Dry-gas Refracks

Like the weather, everyone in the traditional dry gas basins is talking refrack. However, few are doing anything a­bout it.

A percentage of operators are employing gels and ceramics to offset high temperature and high pressure in the Haynesville Shale. Otherwise, it’s strictly slickwater in the Barnett, Fayetteville and Haynesville shales as operators continue to focus on efficiency and cost control.

A majority of operators have settled on a basic completion recipe that incorporates slickwater plug and perf on spacing of about 250 feet between stages, coupled with high proppant loading that currently averages 7.7 million pounds of sand.

While there had been discussion about the opportunity for refracks in both the Haynes­ville and the Barnett, those programs have been put on hold because of the low commodity price environment. This includes Devon Energy Corp.’s widely discussed refrack effort in the Barnett Shale.

Dry gas basin operators are following the same trends evident in other regions, including a steep decline in zipper fracks to just 44% of the market, down from 69% six months ago, as operators slow the pace of completions.