Is the Shale Revolution Here to Stay?

Is the Shale Revolution Here to Stay?

 

Critics of the U.S. shale industry question its staying power.

May 15, 2019
 
 
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Summary

U.S. shale oil is a booming business. As it drives up global oil supply and puts downward pressure on oil prices, U.S. production of shale oil poses a geopolitical threat to other oil-producing states. But critics say that the boom won’t last. If true, that changes the geopolitical calculus.

How much longer will shale oil be a booming business? The answer to that question, while fuzzy, has long-term geopolitical implications. U.S. shale oil production has grown steadily, putting downward pressure on the global price of oil. We’ve written before about the power of shale oil and the impact it has on other geopolitically important oil producers like Russia and Saudi Arabia, which rely heavily on oil revenue to either fund their government spending or support their economies. Our forecasts for these countries are built in part on the assumption that, as the global supply of oil increases, its price will hit a ceiling that could strain these countries’ public finances, which in turn would have political ramifications. But shale skeptics maintain that the industry is not sustainable. If they’re right, and if the shale industry were to die out in the next couple of years, tanking oil supply and spiking oil prices, the geopolitical calculus for Russia and Saudi Arabia would change substantially.

The critics’ argument is threefold. First, they claim that the shale boom depended on huge amounts of debt that was doled out without serious consideration for whether shale producers would be able to pay it back. Second, critics are worried that there’s less shale oil available than originally believed, reflected in shale wells’ depletion rates. Third, they see limited room for growth in the profitability of shale production as shale’s break-even price has stagnated. Combine these factors, the critics say, and you get an industry that will not endure. This Deep Dive will take a closer look at these criticisms and explore whether, in fact, U.S. shale really is an economically sustainable industry.

Shale: A Primer

To understand the criticisms of the industry, it’s important to understand what shale is and how oil is extracted from it – a technically complex and expensive process. Shale rock, embedded thousands of feet under the Earth’s surface, is less permeable than other types of rock. And yet it’s here that shale oil, or “tight oil,” is found. The extraction process for this oil is known as hydraulic fracturing – or “fracking” – and it requires drilling down to the shale deposits, and then drilling horizontally through the rock. The drillers then inject a water-based solution at high velocity to break apart the rock, creating fissures through which oil can flow. (This process can also be used to extract natural gas from shale deposits.)Fracking_Process.png

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The U.S. shale industry really took off in 2009. Thanks to the United States’ extensive shale formations, it has benefited hugely from the shale revolution. The combined technologies of hydraulic fracturing and horizontal drilling vastly increased the productivity of shale wells, and overall U.S. oil production has increased apace. In 2018, the U.S. produced an average of nearly 11 million barrels per day of crude oil, almost 60 percent of which came from shale. It’s helped the U.S. surpass Russia and Saudi Arabia in the production of hydrocarbons and is pushing the U.S. toward becoming a net energy exporter, a benchmark it’s expected to reach next year.

Financing: The Catalyst

Financing was, in many ways, the engine that drove the rise of shale oil, but the industry’s reliance on debt has also threatened to bring it down. In the wake of the 2008 financial crisis, interest rates fell, making debt cheaper and borrowing easier. In the low-interest rate environment, investors were looking everywhere for yield. Shale looked particularly appealing for debt investors since reserves could be used as collateral – if companies failed to pay their debts, the banks could simply take control of the reserves. This created the appearance of added security.

The availability of cheap, accessible debt coincided with two other important moments that created a turning point: skyrocketing oil prices and technological developments that had made the economics of shale drilling viable (though still expensive). Shale production took off, reversing a decadeslong decline in U.S. oil production that had begun in the 1970s.

Debt, however, is a double-edged sword. In exchange for immediate access to capital, firms assume higher operating costs down the road. This can lead to firms becoming over-leveraged as they assume so much debt that they cannot afford to both pay off the debt and pay regular operating expenses. So when oil prices tanked in 2015-16, many over-leveraged companies went out of business, causing U.S. oil production to drop from about 9.4 million bpd in 2015 to 8.8 million bpd in 2016. Notably, this was not an accident. Global oil supply had been climbing thanks to shale production. When supply is too high, OPEC typically cuts production to drive prices back up. But in 2015-16, OPEC chose not to cut supply, hoping that low prices would drive shale producers out of business and thus allow OPEC countries to reclaim market share they had lost to shale.

This downturn threatened to prove right concerns that, without high oil prices and access to cheap, plentiful debt, shale is not an economically viable industry. Companies had taken on unsustainable amounts of debt to fuel growth. When interest rates began to climb, the need to service that debt was a further incentive for shale companies to continue production – even if operations were barely or not at all profitable. These firms’ lending used to set up new wells created debt service expenses, which led to total operating expenses exceeding cash coming in from operations for too long; if interest rates had continued to rise, the entire industry would be, if not sunk, at least forced to slow production. This was not lost on debt investors, who of course feared that bankruptcies would wipe out most of their investment. As oil prices fell, access to debt capital decreased, forcing cash-strapped shale companies to turn instead to equity financing (that is, to issue more stock).US_Shale_Financing.png

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Bankruptcies did, in fact, increase substantially when oil prices plummeted in 2015-16. Banks, as they are wont to do, had offered loans based on current or recent conditions, without consideration for what would happen when oil prices dropped – an inevitability in a cyclical industry like oil. Meanwhile, larger companies bought up the assets of the smaller, less efficient ones, leading to industry consolidation.

But the cycle continued, despite OPEC’s best efforts to keep prices down long enough to destroy the shale industry, and conditions improved. As a number of companies went bankrupt, oil supplies decreased, and prices rose once again. The companies that survived were forced to cut their capital expenditures, which actually led to an improvement in cash flow. Since 2016, bankruptcies have declined significantly.US_Oil_Bankruptcy.png

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Still, some industry observers continued to insist that the economics of the industry itself – not just of individual companies – were fundamentally unsustainable because they relied too heavily on debt. They claimed that debt was not just one factor in shale’s growth but in fact the decisive factor. Without it, they said, the industry couldn’t survive, because total expenses, including debt services fees, would continue to exceed revenue. Since 2016, however, shale drillers have moved toward positive, or at least neutral, cash flow. As of early 2018, a greater share of shale companies was beginning to cover the cost of new wells with operating cash flow, rather than debt. Rystad Energy, an oil and gas market research firm, anticipates that in 2019 shale drillers will generate enough cash to cover capital expenses and pay dividends, though just barely.US_Oil_CashFlowBarrel.png

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If shale companies have enough cash remaining to pay dividends – even just a little bit – it’s a sign that they have enough cash on hand to better pay their debts. As of the fourth quarter of 2018, about 40 percent of companies in a 33-company sample of shale producers were cash-flow positive. To be economically viable, more companies will need to at least break even – in the case of shale, that means they need to generate enough cash from operations to cover their operating expenses without external capital.US_Oil_CapexCashFlow.png

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So, while a good number of shale companies do seem to be in precarious financial situations, many are trending toward positive cash flow. And just because some companies are at risk of going out of business doesn’t mean that shale oil production will cease. Truly cash-strapped companies can sell their assets to major international oil companies that have diversified revenue streams and can keep shale machinery offline until oil prices rise. In other words, as time goes on, the shale industry will mature and, like any industry, experience both bankruptcies and consolidation as some companies prove to be more efficient operators than others.

Oil Reserves: Estimating What’s Out There

But it’s not just financing that shale skeptics criticize. They’re concerned, too, that shale companies substantially overestimated their reserves. They’re not wrong; many oil companies have had to revise their total reserve estimates downward, and it seems their initial overestimations were directly related to the question of financing. If companies had higher reserves – a form of collateral – they could take on more of the debt they needed to get underway. Similarly, when debt financing dried up in 2015-16 and companies started to issue stock, they overestimated their reserves so that it would be easier to raise money from investors.

How were oil companies able to convince banks and investors that their oil reserves were larger than they actually were? Oil-producing companies in the U.S. are required to file with the Securities and Exchange Commission estimates of their “total proven oil reserves” – the reserves for which there is a 90 percent chance that the oil will be recovered. But as the fledgling shale industry was starting to raise money, companies began to use a metric called “estimated ultimate recovery” instead. EUR simply refers to existing reserves, without indicating the likelihood of recovery. The metric is also based on the assumption that, as time goes on, companies would be able to replicate their early success – that additional wells would produce as much as already tapped wells. In retrospect, this was flawed logic; the initial wells are almost always the most productive ones. Shale drillers also assumed they could pack shale wells close together. But packed too tightly, the wells would pull from shared reserves, decreasing the amount that each could draw. Both assumptions contributed to overly optimistic EUR numbers.

In response, investors are now scrutinizing shale producers’ claims. They began by questioning shale companies’ estimates of their reserves – and therefore whether they were worth investing in – and have started pushing for greater accountability in firms’ capital expenditures and demanding higher returns. As a result, shale companies are now exercising more oversight of capital expenditures, cutting spending, moving toward positive cash flow, and using that cash flow to return dividends to investors or to buy back shares. All of this is bolstering the economic sustainability of the industry.

Shale producers’ estimates affect more than just financing. Market research firms and the U.S. Energy Information Administration (which is responsible for collecting and reporting economic data on the energy industry that is used in policymaking and economic forecasting) take into consideration the reserve estimates that companies put out. Historically, forecasts of U.S. shale oil production have been outstripped by actual production, and current forecasts are almost uniformly positive – the EIA and industry consulting firms Rystad Energy and Wood Mackenzie all anticipate substantial increases in oil production over the next 10 years, even with lower oil prices. That’s good news for the shale industry – even with more conservative estimates of their reserves, shale oil isn’t going anywhere.US_Oil_ProductionForecasts.png

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The industry also stands to benefit from pipelines scheduled to come online in late 2019 and early 2020. Production has been constrained by a lack of transportation infrastructure in the U.S., and these pipelines will facilitate transport of resources from the Permian Basin, the source of nearly one-third of U.S. oil output, to refineries and export centers in places like the Gulf Coast. It seems shale oil production will continue growing, though at a somewhat slower pace than the industry initially anticipated.Global_Oil_Reserves.png

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Supply and Profitability: The Geopolitical Question

Ultimately, what affects geopolitics is not the durability of one shale company or another – it is the price of oil and whether the supply of oil continues to increase. And even if the growth in U.S. shale oil production slows, the industry will likely persist for at least the next decade. Skeptics have questioned the shale industry’s ability to sustain high levels of production since it took off over a decade ago. But U.S. production has often outperformed forecasts, and we have to keep this in mind when examining claims that the shale industry is not financially viable.

One of the primary concerns here is the industry’s profitability. As the industry has grown and matured, the break-even price per well has come down. But some doubters claim that there are fewer gains to be made through technological advances. If true, this would mean that the break-even point will not come down much further, leaving little room for growth in the profitability of shale. This may be a valid criticism. But that still puts the profitable oil price for a lot of shale companies well below Saudi Arabia’s fiscal break-even point (the point at which the government can balance its budget), which the International Monetary Fund says is currently about $80-$85 per barrel.US_Oil_BreakevenPrice.png

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Another, more convincing critique examines the relationship between long-term supply and profitability. It’s based on comparing production rates in the Bakken Formation and the Eagle Ford Group, some of the earliest shale basins to be tapped, with the Permian Basin, whose development only took off in 2013. The U.S. has seen net oil production gains since 2016, and much of those gains were from new wells, especially in the Permian Basin. Meanwhile, however, production in Bakken and Eagle Ford has declined following the 2015-16 downturn. (Eagle Ford has stagnated, while Bakken has only recently inched above its pre-2015 production levels.)US_Oil_Basins.png

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Since Eagle Ford and Bakken are older discoveries than the Permian, critics suggest that the former are more representative of what shale basins will be capable of producing after several years of drilling, and that those production levels will be much lower than following the initial discovery, when only the choicest wells were being drilled. The Permian’s production has an outsize effect on total U.S. production. If it follows the trend of its predecessors, that effect would be problematic.US_Oil_Regional_Production.png

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New wells usually produce more oil at the outset, and the rate at which oil flows thereafter is called the decline rate. The Permian’s decline rates are rising faster than expected. Take, for example, Wolfcamp – one of the drilling areas within the Permian Basin. When drilling in the Permian got underway in 2013, observers expected decline rates of 5-10 percent; but Wolfcamp’s rate is now closer to 15 percent annually. Shale companies will need to drill more wells just to keep producing the same volume of oil. If Eagle Ford, Bakken and Permian production all stagnate or decline, that could constrain the amount of oil the U.S. is able to produce in the long run.

That’s assuming no new reserves are discovered. But, in fact, new reserves are discovered often – even in the Permian itself. In December, the U.S. Department of the Interior reported that the Permian’s Wolfcamp and Bone Spring Formations contain the most oil and gas resources of any location ever assessed. Still, that was not an assessment of proven reserves – those that can be recovered using existing technology – but rather of undiscovered reserves – defined by the department as “resources postulated, on the basis of geologic knowledge and theory, to exist outside of known fields of accumulations” – and technically recoverable reserves – defined as “resources producible using currently available technology and industry practices.” For now, companies are poised to continue producing enough to fuel growth in U.S. oil production. But if Permian production stagnates, they may well have to keep finding more reserves – and ways to extract them – to make it last.

What’s Ahead for Shale

The cycle of the oil industry goes on. Demand for oil may decline as countries shift toward fuel-efficient and electric vehicles. But demand for petrochemicals (chemical products for which oil is an input) will continue to grow as more people in the world’s most populous countries – namely, India and China – move into the middle class. The growing demand for oil will drive prices up, enabling shale drillers to increase production and, therefore, producers to rely less on debt – and even to start paying dividends.

It’s no surprise, then, that countries that rely heavily on the oil industry are having to rethink the underpinnings of their economies. (Saudi Arabia, for example, is working to reconfigure its economy to depend less on oil.) The U.S. could also become energy independent, which could have significant geopolitical implications.

The combination of hydraulic fracturing and horizontal drilling, which paved the way for the shale revolution in the U.S., is out of the box and can’t be put back in. The technology will continue to allow the U.S. to produce large quantities of oil for the foreseeable future. Shale isn’t going anywhere – and it will have a major influence over the global economics of oil for at least the next decade.

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Big oil’s investments in Permian pay off as earnings soar

Big Oil is starting to see its billions worth of investments in the Permian Basin pay off as production soared and the fourth quarter of 2018 brought higher-than-expected profits.

Chevron Corp., one of the biggest producers in the region, as well as Exxon Mobil and Royal Dutch Shell, all reported higher profits thanks to the increased flow of oil out of West Texas.

These oil majors were mocked for nearly missing the shale revolution when they lost out to faster-moving independents a few years ago, but in the years since, they’ve purchased hundreds of thousands of acres in West Texas, investing billions in land, rigs and drilling programs.

 

Chevron pumped 2.93 million barrels per day in 2018, the highest ever annual production in the company’s history, and Exxon’s production crested 4 million barrels a day for the first time in almost two years.

 

In the Permian Basin alone, Chevron saw its annual production jump 71 percent last year, hitting 310,000 million barrels per a day annually.

 

Shell, while significantly behind Chevron in terms of Permian production, still saw its production hit 145,000 barrels of oil equivalent per a day in the region, a 200 percent increase compared to January 2017, the Anglo-Dutch major said. As for Exxon, its Permian production soared 90 percent from the same time last year in the fourth quarter.

 

“The growth they’ve been able to achieve in terms of their Permian output is pretty spectacular,” said Lysle Brinker, director of equity and energy research IHS Markit. “They still might not be as good as executing in unconventional plays (as independent companies), but they've gotten a lot better,” he said, noting well completions, drilling and efficiency.

With deep pockets to develop technologies and snatch up additional acreage, plus strong relationships with service companies, majors will see the Permian become in an even bigger part of their portfolios, Brinker said.

“We think there’s going to be more consolidating in the Permian and the big guys could be bigger players,” Brinker said.

Majors also can benefit from integration of Permian output into their refining and downstream portfolios. Recent announcements speak to that trend: Chevron purchased a Pasadena refinery to process lighter crude; Exxon Mobil has plans to increase output at its Beaumont refinery by 65 percent amid a $20 billion plan to grow its manufacturing on the Gulf Coast; and Shell recently started up an expanded petrochemicals complex in Louisiana.

 

With U.S. oil production 23 years ahead of schedule, the majors are retrofitting Gulf Coast refineries to better process the lighter grade crude of the Permian, instead of the heavier crudes of Canada and Mexico, and expanding petrochemical operations to take advantage of relatively cheap natural gas production in West Texas.

 

Exxon CEO Darren Woods said on the company’s fourth quarter earnings call that investments in Texas refineries are really "a transportation play" to take advantage of Permian crude.

"We believe our approach will deliver the lower cost supply and give us a significant advantage," he told investors in the fourth quarter earnings call.

 

 

The integration of its manufacturing and midstream businesses in North America helped to partially offset lower refining margins across the company. Overall refining earnings climbed 73 percent the fourth quarter, reaching $2.7 billion from $1.56 billion the same time last year.

The Irving oil major said Friday that fourth quarter net income slipped to $6 billion, down from $8.3 billion the same time last year. But strong production in the Permian Basin and healthy refining earnings helped bump up its annual net income to $20.8 billion compared to $19.7 billion the year earlier, a 5.5 percent increase.

Woods signaled plans for Exxon to boost its capital spending and asset sales next year. Exxon plans to spend $30 billion on capital projects this year, a 16 percent increase from 2018.

Chevron said Friday that it earned $3.7 billion in the fourth quarter, up from $3.1 billion during the same period in 2017, and beat analyst expectations. Its full-year profits leaped more than 60 percent, to $14.8 billion, from $9.1 billion in 2017.

 

Chevron added 1.46 billion barrels of oil reserves in 2018, with the largest additions in the Permian Basin and LNG projects in Australia.

 

Chevron CEO Michael Wirth said he’s pleased with the company’s position in West Texas, particularly with regards to the company’s land and oil reserves. Chevron claims over 2 million acres in West Texas — it transacted over 150,000 acres of that between 2017 and 2018 — and the company has an estimated 11. 2 billion barrels of oil-equivalent reserves in the region. Wirth said he expects their oil reserves to continue to increase in the Permian.

Chevron expects to spend 3.6 billion in capital and exploratory expenditures in the region this year.

 

Shell, while not as big of a player as Exxon or Chevron, is on the hunt for more Permian Basin acreage. Shell is said to be eyeing a purchase of Endeavor Energy, which controls drilling rights on more than 300,000 acres of mostly undeveloped land in the Permian Basin in Texas and New Mexico, according to media reports.

Shell saw full-year profits jumped 36 percent to $21.4 billion in 2018. Stronger performance in the fourth quarter was driven by higher oil and gas prices, year-on-year, as well as a stronger contribution from liquefied natural gas (LNG) trading, the oil major said.

 

ConocoPhillips, while under-represented in the Permian, also beat expectations this quarter. The company plans to ramp up U.S. shale production this year. CEO Ryan Lance said on the fourth quarter earnings call that he sees a 25 percent increase in U.S. shale growth for ConocoPhillips this year driven by improvements in technology.

 

Bloomberg Intelligence energy analysts Fernando Valle and Jonathan Mardini wrote in a note that they believe ConocoPhillips, a $75 billion company that they call the “poster child” of financial discipline, will look to expand activities in the Permian this year.

marissa.luck@chron.com, erin.douglas@chron.com

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U.S. crude output rises 2.1% in March to near record high: EIA

 

U.S. crude oil production rose 241,000 barrels per day (bpd), or 2.1 percent, in March to 11.905 million bpd, just below its record high, the Energy Information Administration (EIA) said in its monthly 914 production report on Friday.

That monthly increase in U.S. production from a revised 11.664 million bpd in February followed two months of declines in January and February. U.S. monthly output peaked at 11.966 million bpd in December.

Most of the increase came from the federal offshore Gulf of Mexico, which rose 11.1% to 1.907 million bpd, and North Dakota, which gained 3.2% to 1.352 million bpd.

 

Output in Texas, the biggest oil producing state, meanwhile, eased 0.1 percent to 4.873 million bpd.

Meanwhile, monthly gross natural gas production in the Lower 48 U.S. states rose to a fresh record high 99.3 billion cubic feet per day (bcfd) in March from the prior high of 99.1 bcfd in February, according to the report.

Those gains were driven by an 8.7% rise in the Gulf of Mexico to 2.9 bcfd and a 7.2% increase in North Dakota to a record high 2.8 bcfd.

 

In Texas, the biggest gas producing state, output declined 0.9% to 26.4 bcfd from a monthly record high 26.6 bcfd in February.

In Pennsylvania, the second-biggest gas-producing state, output rose 0.7% to a record high 18.8 bcfd.

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Progression Of Completions

The evolution of designs hastens the U.S. shale boom.

In the 70 years since the first hydraulically fractured well began commercial operations, the technique’s processes and designs have undergone a sea change—and in some cases a tsunami—that have led to unconventional oil and gas production being the catalyst to the U.S. shale boom.

Both the micro- and macro-evolutions of completion designs toward high-intensity completions have led to a drastic reduction in breakeven production costs. In 2015 North American shale ranked as the second most expensive resource, according to Rystad Energy’s global liquids cost curve, with an average breakeven price of $68/bbl. The average Brent breakeven price for tight oil is now estimated at $46/bbl, according to the May 2019 press release from Rystad Energy. 

The cost reductions have not been a result of a single innovation, or even just a few. As Pioneer Natural Resources explained in a paper presented at last year’s Society of Petroleum Engineers (SPE) Annual Technical Conference and Exhibition, design teams must consider more than 20 different design parameters for a well’s completion, including proppant and fluid type and amount, cluster spacing, stage length and well spacing. In addition to the multitude of completion components, the reservoir’s characteristics such as thickness and rock properties must be well understood, as they can change significantly across a field, Pioneer explained.

Mike Mayerhofer, director of technology for Liberty Oilfield Services, cited increasing treatment sizes, the move away from crosslinked gels to slickwater fracs and increasing proppant intensity as the primary drivers behind enhanced well completions.

“The driving point is that the data are showing that the extra incremental oil you’re getting with this more aggressive approach is justifying the cost,” Mayerhofer said.

Halliburton’s vice president of production enhancement, Michael Segura, explained that the most significant technologies that have played a role in the evolution of enhanced completion designs are those geared toward efficiencies, such as the adoption of pad drilling. Pad drilling, he said, gave rise to a manufacturing type of well design that would produce multiple wells at once on the same footprint.

“This, in turn, pushed the evolution of completion tools by driving cost down due to volume, coming up with new materials for reduced mill-out time, or no mill-out time at all, and increasing the total number of available stage counts,” Segura said. “The whole process is a very unique balance between operational execution and the technology that enables it where one is always pushing the other.”

Bakken
Hess is a leading operator in the Middle Bakken and Three Forks with about 550,000 net acres and an estimated 2019 production to be 135,000 to 145,000 boe/d, according to the company’s presentation at the Scotia Howard Weil Energy Conference in March.

Hess’ financial and production metrics have experienced a marked increase following its move to plug-and-perf (PNP) completion designs and improved well spacing after the price collapse of 2014. The company reported in its December 2018 investor presentation that its adoption of PNP completions is forecast to result in increases in production to about 200,000 boe/d and net present value by about $1 billion.

But as recently as 2017, Hess was utilizing sliding sleeve completions full scale in the Bakken in its efforts to find revenue in the price-depressed market, as Barry Biggs, vice president of onshore, explained.

“We decided to double down on what we’d been working on up to that point of our journey, which was the sliding sleeve completion,” he said. “The technological component of that was adding additional stages. So, back in the 2013 time frame, it was 10 to 15 stages. By 2014 it was 30 stages, and by the time we got to 2017, we were at 60 stages. We really focused on driving the sliding sleeves to its technical limit.”

Biggs said that during that period, Hess worked to drive costs down by about 40% since 2014.

“We were about $4.8 million per well cheaper than our competitors in 2015,” he said.

With a lower cost structure and rebounded prices, Hess continued adding entry points through PNP completion technology to increase production.

“Each area acts a little bit differently in the Bakken,” he said. “There’s no one-size-fits-all. Plug and perf offers the ability to add more entry points, which is the key here.”

Hess A PNP completion design provided Hess the ability to add more entry points versus an openhole sliding sleeve completion. (Source: Hess)

In addition to stage spacing and the shift to PNP completions, Hess has substantially increased its proppant loading design. Biggs said that in about 2014, when Hess was moving from 25 stages up to 60, its completion designs included about 70,000 lb per stage of proppant. That amount has more than tripled to as much as 280,000 lb per stage.

 

“So that puts us in the 8-million- to 12-million-pound loading across the well now, compared to as low as the 3.5 million we were doing back in about 2014,” Biggs said.

He added the company primarily uses 40/70 mesh sand, and while it has employed some uses of 100 mesh, it has yet to adopt the finer proppant types fully.

Hess also has shifted away from crosslinked gel frac fluid from previous completion iterations, Biggs said, while also bypassing slickwater fracs, which have been in favor for much of the shale industry over the past few years.

“We have really been focused over the last three or four years on a high-viscosity friction reducer [HVFR], and we’ve been very successful with that,” he said. “Some people have gone with the slick water, but we’ve stayed with this HVFR that we perfected in the Utica and brought it back to the Bakken.”

While operators in many North American shale basins have the flexibility to experiment or apply extended, or even “super long,” laterals—sometimes up to 4.8 km (3 miles)—drilling regulations in North Dakota limits well lengths based on drilling spacing units (DSU). The State of North Dakota set DSUs at 1,280 acres, which effectively limits laterals to 3,048 m (10,000 ft).

According to an SPE paper by Liberty Oilfield Services, average lateral lengths in the Bakken and Three Forks have essentially remained constant at about 2,590 m (8,500 ft).

Biggs said Hess has also mostly avoided problems with parent/child well interactions, despite seeing some pressure responses between wells. He said the company’s well spacing design in its core acreage averages about 152 m (500 ft) between wells, whereas others in the region are at about 243 m (800 ft).

“As we moved forward, we’ll be testing different spacing designs,” he said. “We’ve taken the tack that tight spacing generates the highest value, not necessarily per well, but per DSU at that 500-ft spacing.”

Biggs said finding the right completion formula could improve Hess’ noncore acreage position on a scale with its core acreage. 

“In terms of sand loading, the number of entry points and well spacing, all of those variables interact here,” he said. “And we’re trying to find the right recipe in each of those areas to pull our Tier 2 and Tier 3 acreage into Tier 1.”

Haynesville
Goodrich Petroleum controls a combined 23,000 acres in the Haynesville core with proved reserves in those plays of about 13 Bcm (471 Bcfe). The company’s annual production has grown from about 849 cu. m /d (30,000 cfe/d) in 2017 to an estimated 3,964 cu. m /d (140,000 cfe/d) this year, according to its fourth-quarter 2018 investor report.

Robert Turnham, president and COO of Goodrich Petroleum, explained that when the company began developing the Haynesville, its completion designs were based on short laterals and small amounts of proppant. Goodrich’s original completion designs featured 1,402-m (4,600-ft) laterals, 1,000 lb/ft of proppant loading, 91-m to 137-m (300-ft to 450-ft) frac intervals and cluster spacings of 15 m to 21 m (50 ft to 70 ft), and a hybrid design of gel and slickwater frac fluid. The result, Turnham said, was underperforming wells.

“A much wider interval with much less proppant per foot was creating much poorer stimulation,” he said.

After gas prices in 2014 fell from $6/MMBtu to about $3.50/MMBtu, Turnham said Goodrich looked to test different stimulation methodologies. The result was longer laterals, higher proppant loading, a shift to exclusively slickwater fluids, tighter frac intervals and closer cluster spacing.

“It became clear that if you tightened your intervals and increased your proppant, that would make a huge difference,” he said. “So we tested all the way to 10,000-ft laterals and 5,000 lb/ft of proppant and less than 100-ft (30-m) intervals, and clearly that combination made the best wells drilled to date in the Haynesville.”

Turnham noted, however, that the higher-density completion design also came with a higher cost.

“Then the question is how to tweak that so you’re not only getting a superior reserve but also generating the highest rate of return,” he said.

Goodrich’s current completion design now features on average 2,286-m (7,500-ft) laterals with 4,000 lb/ft of proppant and cluster spacings of between 4.8 m and 6 m (16 ft and 20 ft). Turnham said the transition away from gel to slick water has resulted in better cracking of the rock in the frac intervals.

“The goal here is near-wellbore stimulation versus wing length reach away from the wellbore, because the farther out you go, the more the likelihood that the frac is going to close up on you,” he said. “You’re just not going to capture as much of the gas that’s in place unless you tighten up the intervals. And that’s what we’re seeing—higher recoveries from better stimulation.”

Although Goodrich tested 3,048-m laterals, Turnham said the company settled on the shorter 2,286-m wells at least in part to more consistently drill on budget. Replacing mud motors or drilling tools is more costly with longer laterals as a result of the time it takes to retrieve and replace the tools, he said.

“By the time you come up to the surface and get back down to drilling, it could add three days to your drill time,” Turnham said. “Every day costs you $75,000 to $100,000, depending on what tools you have in the wells. So, it’s not that you have risk drilling from 7,500 ft to 10,000 ft, it’s that you have a higher probability that you could exceed your budget or estimate to drill that well.”

In addition to fine-tuning the parameters of its completion design, Turnham said Goodrich has also begun to implement dissolvable plugs into its operations. He said the company first utilized dissolvable plugs in its operations in the Tuscaloosa Marine Shale in 2013 through about 2015.

“For the technology back then, those plugs were not as good as the plugs are now, and in the early days dissolvable plugs might not have kept a grip or hold when you’re fracking,” he said. “They might not dissolve properly, or they might create this emulsion that would mix with your clays and sands.”

Turnham said the modern dissolvable plugs Goodrich applies hold and are easier to clean out. In addition, he added Goodrich, like many other operators in the Haynesville, has turned almost exclusively to PNP  completions rather than sliding sleeves.

“It’s a better methodology to ensure that you’re stimulating equally over an interval through your perforation,” he said. “We’ll put 35 perforations over a 100-ft interval, and if you pump your fluid at 2 bbl/min per perforation, you’re equally distributing the fluid out over those perforations, and therefore, we think you get a more uniform completion than if you just had a sliding sleeve that basically opens up the interval.”

Midcontinent
Chaparral Energy is a pure-play Stack/Merge operator that reported 14,400-boe/d Stack production in 2018, an increase in production of 52% over 2017. According to the company’s May investor report, Chaparral’s drilling and completion costs in the Osage and Meramec are just more than $800/lateral ft, about $200 less than the average cost per lateral foot among its peers in those plays.

Similar to Goodrich Petroleum, and a host of other operators, one of the primary goals in the company’s completion designs is to optimize near-wellbore stimulation, said Jim Miller, Chaparral’s senior vice president of operations.

“Our stimulation job has changed quite a bit over the last several years,” he said. “Instead of trying to reach out and touch someone with the frac job, we’re trying to create a more complex near-wellbore fracture.”

To improve conductivity, Chaparral employs cemented liners and low viscosity frac fluids with 100 mesh proppant, a change from the 40/70 and 30/50 sands and cased and cemented wellbores the company initially utilized in the Stack. Josh Walker, Chaparral’s vice president of completions and operations, said thinner frac fluids combined with finer-mesh sands and minimal chemicals and acids are easier to place within the fracs.

“It’s hard to place a decent concentration of 40/70 or 30/50 [proppant] with really thin fluids,” he said. “You open up your options when you’re placing 100 mesh, and so we’ve gone away from any viscous fluids.”

Chaparral is also among the operators that have found improved results deploying diverters in its completion operations to achieve improved cluster efficiencies. Walker said Chaparral has improved its understanding of diverting agents and their impact on cluster efficiency through the use of fiber optics over the last few years.

“That’s been one of the driving factors in finding a diverting agent that actually works, and that’s been one of the things the whole industry has been looking for over the past six or seven years,” he said.

Walker said the early diverters designed with polyactic acid or fibrous materials were not as effective as current designs.

“The TTS [Thru Tubing Solutions] pods are the first thing we’ve found that actually do what they’re designed to do, which is to plug up that major runaway fracture,” he said. “So that’s how we mitigate risk, because we’ve added a few clusters per stage and we mitigate the potential of decreased cluster efficiency with a diverting agent.”

In addition to applying diverters more so than in previous completion designs, Chaparral is now testing dissolvable frac plugs to use in place of traditional plugs. Walker said dissolvable frac plug technology has improved over previous iterations while the costs have come down to a point where their use is more justifiable.

“[Dissolvable plugs] would help a whole lot in the Stack,” he said. “It’s less of an issue where you’ve got all the pressure in the world, but if you can find something to help mitigate the risk of drill out, it’s a big step.”

Also similar to other operators, particularly in the Stack. Chaparral has reevaluated its well spacing plans to avoid potential parent/child well interference. The company has tested well spacing designs at its Denali, Foraker, King Koopa, Hennessey and Jester units as well as at some of its nonoperated units.

During the fourth quarter of 2018, Chaparral brought online its first operated partial spacing test in Kingfisher County, Okla. Chaparral CEO Earl Reynolds said during the company’s fourth-quarter 2018 investor call that the five-well King Koopa test included three Meramec and two Osage wells and was drilled in a section with an original Meramec parent well.

“We did not see any hydraulic communication between the infill wells, which is a good sign that our frac was contained to near-wellbore as per our design,” Reynolds said. “Another sign of the frac design effectiveness is the fact that the parent well has successfully returned to its pre-infill production rate.”

Reynolds said those results give the company confidence in its frac design and spacing plan as it moves toward full-section development. Walker explained that design has evolved and the company now believes it can successfully develop three or four wells per drillable bench. Miller added that Chaparral has introduced, when economically feasible, repressuring and refracturing parent wells.

“When you start looking at repressuring the parent wells, that’s an additional cost to the job,” Miller said. “To make those wells economic, you have to include that cost to repressure the parent [wells]. If we can do that, and improve your child wells, then we feel like we’re better off.”

Marcellus-Utica
In March Appalachia operators Blue Ridge Mountain Resources and Eclipse Resources merged to form Montage Resources. The merger resulted in, among other dynamics, a focus on improving the economics, and subsequently the returns, of its well designs. The former Eclipse Resources made headlines for its “super long” laterals, which averaged 5,600 m (18,375 ft). In 2017 the company set the world record for the longest lateral at 5,882 m (19,300 ft), or 6 km (3.7 miles).

But now, under the Montage Resources moniker, those lateral lengths have tapered off a bit, said Douglas Kris, vice president of investor relations.

“What you’ve seen more recently with regard to the new company is a reigning back in terms of lateral length, and it’s due not to the inability to drill out that far or the degradation of recovery,” he said. “It’s more driven by the market environment these days, which is focused on generating cash flow quicker.” 

According to a company investor report, Eclipse’s wells averaged about 4,694 m (15,400 ft) in length in 2018. This year that distance has been reduced to an average of about 356 m (11,700 ft), a decrease of 25%. The result has led to a reduction in cycle time of about 20% from 220 days to about 175 days, which, as Kris explained, improves the return to capital.

“If you drill four 20,000-ft [6,096-m] laterals, you’re talking nine to 11 months from when you spud until you start to see cash flow,” he said.

Also driving economic returns has been the company’s evolving plan for proppant loading and stage spacing. About two years ago, Eclipse was loading proppant at about 3,000 lb/ft with stage spacings of 45 m to 61 m (150 ft to 200 ft), Kris said.

“What we’ve learned is that the stage spacing is probably correct in roughly that 200-ft spacing, but the proppant loading is closer to 2,500 lb [per foot], and not over 3,000 lb [per foot],” he said. “Because with each pound you’re getting a diminishing return, and you’re not necessarily getting additional EUR for the incremental sand that you’re putting down there.”

Such a design, however, is not applied uniformly throughout an entire well or a well pad, Kris explained.

“What we’ve found is that like rock stimulates better with like rock,” he said. “So if you see something in the rock characteristics that would result in a stage at 250 ft [76.2 m] as opposed to 200 ft because the rock characteristics are the same across the entire stage, then the proppant gets put away evenly in that entire stage. Whereas if you just had a 200-ft stage and you had different rock characteristics throughout the stage, your proppant is going to get placed more in one area and not the other. You won’t get the full effect of the cost that you’re putting down there.”

Part of the success of Eclipse’s super long laterals, at least in terms of production, was the ability to push proppant into the reservoir so far from the spud location, an effect of improved fracture fluid applications and the adoption of mostly 100 mesh sand, Kris said.

“We moved away from the crosslinked gels, which is what we used initially in 2013 and 2014,” he said. “We’ve moved away from that to more slick water, and we’ve found that to be much better and much more beneficial for the life of the well and the preservation of the reservoir.”

The high pressures of the Appalachian Basin often present challenges when applying technologies and tools that have proven successful in lower-pressured environments. Among those are dissolvable plugs. Kris said Montage has only moved into the testing phase for dissolvable plugs but is hesitant for widespread adoption.

“I think part of that is just the trepidation in Appalachia just because of the rock characteristics,” he said. “You’re a lot deeper and the pressure is a lot higher, especially in dry gas. We haven’t had any issues, but we’ve seen some issues from other operators with whom we have a working interest. So we’ve never holistically used it for an entire lateral.”

Future of completions
Montage’s inclination to cut back on its lateral lengths, along with similar signs in nearly all shale basins, is an indication the industry might be seeing an end to the continuation of higher-intensity completions. Operators and service companies are beginning to see diminishing returns from increasing proppant loading, extending laterals even farther and setting frac stages closer together. Meanwhile, frac hits resulting in lost production are causing companies to reevaluate their well spacing plans.

“This year is probably the first time that we’re seeing it’s a lot more stabilized with proppant,” said Riteja Dutta, senior production manager of analytics and engineering at Drillinginfo. “In fact, in some areas it’s even dropped a little bit from an average of about 2,000 pounds per foot in 2018 to now we’re at about 1,800 pounds per foot in certain areas. And apart from controlling costs, the dynamic of well interference has also changed the conversation of how intense those fracs are.”

Liberty’s Mayerhofer explained that investors are now looking for companies to improve their profit margins and become cash-flow positive, which drives cost reductions and, subsequently, modified completion designs.

“I think people have taken their foot off the gas pedal a little bit,” he said. “When we do our Big Data studies, we definitely see that as you go larger and larger on treatment sizes, we see production has diminishing returns.”

Halliburton’s Segura explained that the limits on completions are an indicator of an evolution in technology. That evolution, he said, will likely lead to newer approaches to future completion designs.

Halliburton’s frac plug technologies Halliburton’s frac plug technologies have evolved from cast iron such as the Obsidian Frac plug at top to the dissolvable Illusion Spire Frac Plug released in February. (Source: Halliburton)

“[Operators] find that they now are pushing the technology and, by association, the whole operational process to its limits,” he said. “These kinds of litmus tests on existing technology, along with the introduction of Big Data and digitalization in the oil field, provide indicators on where technology and processes can improve and what types of innovation are needed to be pushed forward. These pushes can sometimes lead to a new completion approach, new technology, new processes or a collaboration of each.”

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Deepwater Texas Oil Port Developer Seeks MARAD License

Dallas-based Sentinel Midstream, LLC reported Monday that its Texas GulfLink, LLC subsidiary last week submitted a license application with the U.S. Maritime Administration (MARAD) to construct and operate a deepwater crude oil export facility off the coast of Freeport, Texas.

According to Sentinel, the proposed Texas GulfLink terminal would be capable of fully loading very large crude carrier (VLCC) vessels. Currently, the U.S. is home to just one deepwater crude oil port facility: the Louisiana Offshore Oil Port (LOOP).

The Texas GulfLink project calls for developing an onshore oil storage terminal connected via 42-inch-diameter pipeline to a manned offshore platform approximately 30 miles off the Gulf Coast, Sentinel stated. Oil would be transported from the platform to two single point mooring buoys, which would enable VLCCs to receive 2 million barrels of crude oil loaded at rates up to 85,000 barrels per hour, the firm added.

“With the submission of the license application to MARAD, Texas GulfLink has completed a major milestone towards receiving approval to construct and operate a deepwater crude oil export facility,” Jeff Ballard, Sentinel’s president and CEO, said in a written statement emailed to Rigzone. “As the neutral infrastructure export solution for shippers, Texas GulfLink will provide a necessary crude oil export outlet for the expected increase in U.S. crude oil production.”

Sentinel added that Cresta Fund Management is providing project financing and Abadie-Williams served as Texas GulfLink’s primary engineering and regulatory consultant.

“We are pleased with the commercial support Texas GulfLink has received and the continued strong interest from shippers who recognize the need for additional export capacity,” noted Chris Rozzell, Cresta managing partner. “By reducing capacity constraints in Gulf Coast ports and creating an economic oil export outlet, Texas GulfLink will allow U.S. oil producers to continue to develop and increase U.S. oil production without potential production curtailments due to lack of export capacity.”

Other firms vying to develop deepwater crude oil port facilities offshore Texas include Trafiugura US Inc. and Enterprise Products Partners L.P. Trafigura’s Texas Gulf Terminals project would be located near Corpus Christi. Enterprise’s Sea Port of Texas (SPOT) project would be located offshore Freeport. Additionally, Lone Star Ports, LLC – a joint venture of The Carlyle Group and The Berry Group – have proposed building an onshore export facility near Corpus Christi that could load VLCCs.

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Texas Petro Index March/Q1: Activity Down But TX Oil & Gas Economy Expanding

AUSTIN, Texas – Curious trends are happening in the Texas oil and gas industry, according to the Texas Alliance of Energy Producers March Texas Petro Index (TPI). Despite a decline in the March TPI to 212.4 and in the first quarter 2019, prices continue to improve and Texas crude oil production is still breaking records. A monthly measure of growth rates and cycles in the Texas upstream oil and gas economy, the TPI is based on indicators such as rig count, drilling permits, well completions, and employment, which all remained in decline in March.

“Typically, these E&P indicators decline during an observable, sustained contraction in oil and gas activity, but that doesn’t appear to be what we’re seeing now,” Karr Ingham, Petroleum Economist for the Texas Alliance of Energy Producers and creator of the TPI. “I do think these decreases can partly – even largely – be attributed to the sharp and unexpected fourth quarter 2018 crude oil price declines, but clearly there are other forces at work. These have become increasingly evident over the course of the current recovery and expansion from the 2014-2016 industry downturn.”

These forces are the ever-higher efficiencies achieved by Texas oil and gas operators, supported by the numbers. With crude oil production continuing to set milestones, the March monthly average rig count fell below 500, the fourth straight month of decline, compared to a monthly average of 904 in December 2014. The number of drilling permits issued in the first quarter is down by about five percent compared to year-ago levels and is off by nearly 40 percent compared to the 5,367 permits issued in the first quarter 2014.

Direct upstream (exploration and production) industry employment is on the wane as well after reaching a cyclical peak in December 2018.  Seasonally adjusted numbers compiled by the Federal Reserve Bank of Dallas, with further adjustments by the Texas Alliance of Energy Producers (to strip out the few “mining” jobs in Texas that are not oil and gas related) suggest the loss of about 3,500 oil and gas E&P jobs from December to March. Further, the March estimate is down by over 70,000 compared to the all-time peak employment total in December 2014.

Industry employment and crude oil production estimates in March suggest that for every one direct upstream oil and gas employee, about 700 barrels of oil are produced, compared to about 170 barrels per employee in 2009.

Crude oil production continued its upward ascent through the first quarter, however, with daily production exceeding five million barrels for the first time according to Alliance estimates (based on data from the U.S. Energy Information Administration (EIA) and the Texas Railroad Commission).

“Given current price levels, which continue to improve, the Texas upstream oil and gas economy remains in expansion mode,” said Ingham. “But the nature of oil and gas economic growth in Texas is different in 2019 largely because it has become perfectly apparent that Texas oil and gas companies can produce more crude oil with fewer resources deployed.”

The March 2019 Texas Petro Index of 212.4 was down from the February TPI of 213.1, and the December (year-end) 2018 index of 212.9 – and more than 100 points (about 32%) below its November 2014 peak. In fact, the Texas Petro Index has generally been in a state of mild decline since its cyclical peak in October 2018.

Crude oil pricing itself is well below the June 2014 cyclical peak in crude oil prices of over $100/bbl, and natural gas pricing in Texas is increasingly wretched in early 2019 thanks to continued deep discounts in Permian gas prices. The Texas Alliance of Energy Producers Texas Petro Index is based at 100.0 in January 1995.

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Oil & Gas Leaders Look for Cost Reduction and Efficiency Gains

 

Houston – Speaking at the closing of the AIPN 2019 International Petroleum Summit (IPS), Ryan Lance, Chairman and Chief Executive Officer of ConocoPhillips spoke about his company’s “hyper focus on returns” highlighting that the “returns the energy industry has generated have been negative over the last 10 to 15 years. Investors are frustrated. We chase the cycle up only, they have to chase the cycle back down on the back side. We recognize it’s a mature industry growing at 1 percent per year. There’s a lot of companies, some tremendous companies … that have dramatic growth profiles. But when they put a hundred percent of their cash flow back into the business, don’t pay the shareholder a fair amount of money, they’re actually destroying value in the long run.

You’ve got to pay your shareholder upfront, you’ve got to be able to grow and develop your company off the cash flow that’s left over and you’ve got to have a focus on returns on capital employed.”

Technology was a constant theme throughout the two days of the IPS with many of the speakers agreeing that technology is going to play a great part in generating future value. Ryan Lance said, “The revolution that we’ve got going on inside our company is embracing technology, innovation and analytics…is it’s not so much about adding another rig it’s about how do you get more work done with that rig that you’ve got.”

 

Alma Del Toro President, Blue Bull Energy believes that, “Technology, such as unmanned platforms, will change the entire nature of the joint operating agreements. Technology is changing the game plan.” However, she pointed out that, “For a CEO choosing the right technology presents its own challenges.”

With panels on Venezuela and Brazil as well as several sessions on Mexico delegates recognized that South America, despite the huge amount of change in the last six months, would provide important opportunities for the industry’s expansion. When commenting about the political changes in Mexico Alma Del Toro said, “Shell, Murphy and Jaguar have reaffirmed my belief that the new administration has not changed much and that Mexico is open for business. Permits are getting issued and nothing has stopped.”

About the AIPN: The Association of International Petroleum Negotiators is an independent not-for-profit professional membership association that supports international energy negotiators around the world and enhances their effectiveness and professionalism in the international energy community. Founded in 1981, AIPN has over 3,000 members in more than 110 countries, representing international and national oil and gas companies, governments, law firms and academic institutions.

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Examining How Industry Giants Reduced Operational Costs By Going Digital

 

Last year’s tumultuous oil prices saw WTI and Brent both start the year at over $60 for the first time since 2014, the benchmark year for pre-crash prices. Hopes of a true price rebound began to grow as both commodities hit four-year highs several times throughout 2018. For an online archive of how intense the hype became, simply search “will oil prices reach $100 again.” The result is pages upon pages of industry and finance headlines examining the possibility of $100 barrels — the overwhelming majority of which were published in 2018. While the consensus was split, optimists were about to learn a lesson in false hope. WTI and Brent closed the year well below $60 per barrel, prompting the U.S. Energy Information Administration (EIA) to reduce both its 2018 and 2019 forecasts in early December. To add insult to injury early this year, 2019 forecasts were further reduced, along with 2020 forecasted prices. If additional evidence was necessary to illustrate that low prices are the “new normal” for the O&G industry, Q1 of 2019 provided a solid case.

O&G producers and service companies don’t need to reinvent the wheel in order to reduce operational costs. The most capital-intensive
projects in the industry have proven digitization as a model for reducing operational costs. In this article, we take a look at what analysts learned from the industry’s digital pioneers before examining how to scale the same principles to reduce costs and safeguard profit margins in the face of unpredictable market prices.

Follow The Leader: Examining How Industry Giants Reduced Operational Costs By Going Digital

How the Biggest E&P Projects Safeguard Profits

Logically, cost discipline has been the dominant business strategy of O&G producers since 2014. Any hope of realizing profit in the face of dwindling revenues required significant reductions in what was already one of the biggest upstream cost risks: operational costs. The upstream companies that were able to weather the latest price crash found ways to trim the fat and implement lean operating principles. However, this was not the case for the biggest ventures in oil and gas extraction: offshore rigs. Whether it was a response to the 2008 crash or simply the capitalist pursuit of profit, stakeholders in these mammoth projects had already identified, refined and implemented new ways to reduce operational costs.

How did they manage? By embracing the next step in the evolution of industrialization: digitization.

It was mid-2014 when McKinsey & Company published a whitepaper titled “Digitizing Oil and Gas Production.” Using North Sea offshore rigs as benchmarks, they observed that while production efficiency had dropped in the past decade, the performance gap between industry leaders and all others had nearly doubled between 2010 and 2012. Looking for what sparked the differentiation, analysts examined the role of technology. Production was considered “digitally-capable” at this point, with any average offshore rig using upwards of 40,000 sensors to collect massive amounts of complex data. So how did the leaders manage to pull away from the pack? By successfully integrating all that data.

The E&P companies that were able to use data effectively increased production efficiency by ten percent and saw $220 million to $260 million dollar increases to their bottom line. And remember, this shift occurred before the 2014 crash in oil prices. The advantages gained through production efficiency became exponentially more valuable in the face of shrinking revenues as global oil prices plummeted.

Follow The Leader: Examining How Industry Giants Reduced Operational Costs By Going Digital

What Does “Successful Integration of Data” Mean?

 

Data can be used in a lot of ways, from reducing unplanned rig downtime by informing predictive maintenance schedules, to enabling the complete automation of complex, unconventional drilling maneuvers. In fact, automation (the conversion of manual processes to automatic ones) is presently the ultimate means of utilizing data to increase efficiency. Where the Industrial Revolution was marked by the use of iron to enable mechanization, the digital revolution of the 21st century requires vast amounts of data to enable the next step in our tech evolution: automation. Five years ago, when McKinsey & Company identified automation as a “clear competitive imperative” for the O&G industry, prices were over $100 per barrel and the case for large capital investment in new tech was a hard sell. However, in the new normal of sub-sixty dollar barrels, the urgency of automation is clear.

Follow The Leader: Examining How Industry Giants Reduced Operational Costs By Going Digital

Avoid a Cart-Before-The-Horse Scenario: Automation Is Data-Driven

As previously mentioned, automation requires data – and lots of it. Operations such as rigs and refineries are rife with data-capturing opportunities: every sensor, gauge and meter can go from simply displaying information to storing it. However, indiscriminate data collection is unmanageable and will certainly not lead to production efficiencies. Before the rigs examined by McKinsey & Company increased profits by $200 million through intelligent data integrations, stakeholders began with a vision for how the information would be used. This way, only digital outputs that furthered the end goal were selected for collection.

Follow The Leader: Examining How Industry Giants Reduced Operational Costs By Going Digital

Scaling Down: The Path to Automation for On-Shore Producers and Service Companies

Various automations are available to O&G production and service companies without the need for data collection or other R&D. These ready-made solutions reduce operational costs for some common standard processes such as executing a slide or scheduling tool maintenance. If you can purchase the tech, you are able to reduce operational costs. These products are good for your bottom line but they do not result in a true competitive advantage. Pulling away from the pack and creating the significant production gap achieved by the leaders in our case study requires vision, creativity and asking the right questions. Where are the opportunities in your operations? Where is data not being captured? Or, which processes fail to leverage captured data? These kinds of questions produced a proven digital model that also performs at smaller scales. Careful examination of your processes will also lead to a well-informed digital roadmap for reducing operation costs. Consider what can be learned from the timing of the industry leaders in the McKinsey & Company whitepaper as well. Rather than reacting to market changes, these innovators made proactive capital investments before the need was even apparent.

There’s another advantage to following in the footsteps of giants — you don’t need an in-house team of programmers to create bespoke software tools. Thanks to third party specialists, every step of digitization — from the overall vision to field execution — is guided by experts. The management of field crews is one of the biggest opportunities to capture data and improve processes through automation. Even as the digital revolution permeates all other aspects of E&P, field operations remain heavily dependent on paper, leading to revenue leakage and high operational costs. The disconnect between the field and the leadership team results in information lags and errors, making effective cost management impossible.

At Aimsio, we’re familiar with the challenges you face when it comes to managing remote field operations. We also happen to be specialists in creating digital solutions for O&G producers and service companies. To see how our platform makes real-time cost management possible by capturing data in the field, head over to www.aimsio.com. 

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Cheniere, Apache sign historic Permian shale LNG deal

 

Cheniere Energy and Apache Corp. have signed a first-of-its-kind agreement on liquified natural gas. Through a newly announced, 15-year deal, Apache will produce and supply LNG to Cheniere Corpus Christi Liquefaction Stage III LLC, a subsidiary of Cheniere Energy Inc. The LNG price paid to Apache will be based on global LNG indices.

According to Cheniere, Apache has agreed to sell 140,000 MMBtu per day of natural gas to the Corpus Christi facility.

“This first-of-its-kind long-term agreement with Apache represents a commercial evolution in the U.S. LNG industry, as it will ensure the continued reliable delivery of natural gas to Cheniere from one of the premier producers in the Permian Basin,” said Jack Fusco, president and CEO of the gas company, adding that the deal will give Apache flow assurance on its gas.

 

The Corpus Christi Stage III project is being developed to include up to seven midscale liquefaction trains with a total expected nominal production capacity of approximately 9.5 mtpa. Corpus Christi Stage III received a positive Environmental Assessment from the Federal Energy Regulatory Commission in March 2019 and is expected to receive all remaining necessary regulatory approvals for the project by the end of 2019.

Last week, Apache signed a deal with Altus Midstream to handle other portions of its shale gas.

John Christmann, Apache’s CEO and President, said the agreement was made to leverage Apache’s Permian Basin asset scale and diversify its customer base.

Cheniere has one of the largest liquefaction platforms in the world, consisting of the Sabine Pass and Corpus Christi liquefaction facilities on the U.S. Gulf Coast, with expected aggregate adjusted nominal production capacity of up to approximately 45 million tons per annum of LNG operating or under construction.

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Real life Solutions to real life issues in the Shale sector, Permian, solving critical issues with long term, sustainable economically feasible and viable solutions.

________________________________________

 

Exterran lands major water contract with Permian producer

Exterran Corp., a global systems and process company offering solutions in the oil, gas, water and power markets, announces its Water Solutions business has secured a significant produced water treatment contract with a major operator in the Midland area of the Permian basin.

The 30,000 barrels of water-per-day (bwpd) treatment system includes the removal of oil-in-water, suspended solids and iron. Offered as a turnkey package, the provided solution also includes accessories, manpower, and remote monitoring and reporting of water treatment data.

The contract follows a successful three-

month pilot in late 2018, where Exterran met or exceeded oil-in-water, suspended solids and iron outlet performance levels.

Todd Kirk, director of water at Exterran, said: “Over the past two decades, we have had many successful produced water operations around the world in over a dozen countries. These include a wide range of unique solutions designed to help meet any customer need from small mobile units that are lightweight, easy to ship, install and start-up to handling over a million bwpd of produced water at large processing facilities.

“Customers appreciate our expertise, efficiency and operational excellence. By partnering with a turnkey produced water specialist like Exterran, operators not only get a reliable portfolio of technologies, but also a team of experts to solve their water challenges and support them at a moment’s notice. Facility simplification, data acquisition, AI and experienced technicians help to solve manpower limitations in the basin and improve operations efficiency.”  

Exterran offers operators a full range of primary, secondary and tertiary treatment solutions for removing oil, contaminants and suspended solids from produced water. The company designs, builds, and operates systems that quickly, efficiently, and cost-effectively treat produced water ranging in volumes from 100 to in excess of 1,000,000 bwpd. 

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Devon Energy embarks on new US shale focus

Devon Energy is working to become a U.S. shale oil pure-play company following the sale of its Canadian assets. In a deal valued at nearly $3 billion, the Oklahoma-based exploration and production firm has agreed to sell its heavy oil assets to Canadian Natural Resources Limited. Later this year, Devon intends to finalize the sale of its shale gas assets in the Barnett shale gas play of North Texas. A data room for the shale gas assets has already been set up.

Devon’s Canadian assets consist mostly of heavy oil sites in Alberta. The assets generated roughly 113,000 oil-equivalent barrels in the first quarter this year. Last year, the assets in Canada generated roughly $236 million.

“New Devon will emerge with a highly focused U.S. asset portfolio and has the ability to substantially increase returns and profitability as we aggressively align our cost structure to expand margins with this top-tier oil business,” said Dave Hager, president and CEO. “The New

Devon will be able to grow oil volumes at a mid-teens rate while generating free cash flow at pricing above $46 per barrel.”

Devon will now focus on its operations in the Rockies, Delaware Basin, SCOOP/STACK and Eagle Ford.

In the Delaware, Devon has a plan to spend $900 million this year, with another $300 million slated for the Eagle Ford, $400 million to the STACK and $300 million to the Rockies.

In Canada, Devon spent more than two decades working to develop its heavy oil assets.

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More Innovation and tech to make shale better and profitable:

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New Perforating Systems Save Time, Cost

Innovative technology designs are increasing efficiencies.

PERFORATING SYSTEMS TECHNOLOGY SHOWCASE:

Operators are constantly searching for the latest innovations to maximize production. The following technologies are some of the latest products and services available to the industry.

 

Perforating tool simulates and predicts dynamic conditions
Built on advanced analysis and job planning data, Baker Hughes, a GE company’s (BHGE) TerraConnect perforating technology, engineered for reservoir conditions, simulates and predicts the dynamic conditions that occur during perforating events (See image above). These simulations predict transient behavior during laboratory testing, translating to optimum job designs that improve downhole results and reservoir contact. Using its PulsFrac software, BHGE optimizes perforation tunnel cleanup with a variety of technologies, including TerraFORM dynamic underbalance optimization services, TerraPERM propellant perforating optimization services and static underbalance techniques. The TerraConnect perforating technology and PulsFrac software provide a perforating design and cleanup operations optimized for the target reservoir. TerraConnect was recently applied on a multiwell project in Southeast Asia where laboratory test results led to product and deployment technique selection. Collaboration with the operator led to continual operational and production improvement over the course of the project, contributing to the ultimate reduction of wells planned by 33%. bhge.com

Consistent hole size perforating
Horizontal, unconventional wells have revolutionized the industry and fundamentally changed perforating. Consistent hole size perforating has proven highly successful and has become the standard. As production on unconventional wells declines, operating companies are challenged to revitalize these assets through recompletion or refrac methods. Core Lab/Owen has delivered ReFRAC technology to meet this challenge. Mechanically isolated refrac wells with cemented tubulars inside existing well casing are exponentially more complicated to provide consistent holes due to perforating two strings of casing with cement in between. Fracturing is more difficult, resulting in fewer stages per day and increased costs. ReFRAC charges produce optimal and consistent holes to meet these challenges. Two major operators have seen two to three times the number of stages per day completed with fewer perforations. Costs and time on the well were reduced and profit margins increased. Multiple operators are requesting ReFRAC charge technology in this recompletion application. corelab.com/owen

Core Lab/Owen ReFRAC perforating charges shoot consistent holes through two casing stings. (Source: Core Lab/Owen)

Perforating system shortens gun length
The DynaEnergetics DS Trinity perforating system offers three charges in a single plane (three-in-a-plane) to shorten gun length and provide formation benefits during the hydraulic fracturing process. At less than 8 in. overall length, the new system is up to 3.5 times shorter than conventional perforating guns, enabling much higher gun counts per stage. Shorter gun lengths also save on running costs by reducing the height requirements for rigup cranes and pressure control equipment. The single-plane charge architecture has been determined to reduce formation breakdown pressure and achieve optimal rates quicker, which can ease wear and tear on fracturing equipment. In addition, single-plane perforating can lead to better fracture geometry in certain formations, enhancing overall well productivity. Recently completed field trials were conducted in partnership with a large U.S.-based independent operator that provided feedback on key features and functionality of the system. More than 1,000 guns were delivered during the field trial process, which was conducted with 100% success rate. dynaenergetics.com

DynaEnergetics The DynaEnergetics DS Trinity single-plane perforating system is up to 3.5 times shorter than conventional perforating guns. (Source: DynaEnergetics)

Technology eliminates clogged perforations
Kraken technology is a progressively burning, solid propellant designed to increase penetration, eliminate clogged perforations and overcome near-wellbore damage from compaction caused by traditional perforators. Progressively burning Kraken propellant boosters generate high-pressure gas in the perforation tunnels, which creates fractures that improve well connectivity. Completion engineers who scorecard breakdown pressure, IP/II increase, operating time and safety will observe that the return on incremental investment in enhanced perforating performance routinely exceeds 100%. thegasgun.com

Kraken GasGun A cutaway of the Kraken tool in a well is shown. (Source: Enhanced Energetics)

Interventionless perforating tool requires no electronic detonation
Nine Energy Service’s FlowGun technology is a stage one interventionless casing-conveyed perforating tool that eliminates the need to run wireline or coiled tubing (CT) and requires no electronic detonation. FlowGun offers an innovative, safe and cost-effective advantage for stage one completions. It offers infinite efficiency, control and flexibility. With FlowGun, operators see increased savings on time and money because the numerous downhole jobs are consolidated into one tool and one crew with no sleeves to shift, no wet shoe required and no electronic detonation needed. An entire phase of completion is eliminated, removing the need to pay for additional water, tank trucking BOP rental, CT, chemicals and labor. nineenergyservice.com

Sliding sleeve tool helps operators avoid risks
While it is a very widely used completion method, plug and perf can have a negative effect on near-wellbore permeability, as the impact stress associated with the outward traveling shock of a shaped charge weakens the rock matrix and increases the risk of sand production. The i-Frac system from National Oilwell Varco (NOV) helps operators avoid the risks inherent in using conventional perforating methods with explosive charges and guns. The i-Frac is a hydraulically operating sliding sleeve tool that is threaded in as part of the production casing. Using a ball or a coil-conveyed tool, the sleeve is shifted, and perforations are exposed to the inner casing from inside; on the outside, perforations are covered up with cement. After this, a pressure increase breaks through the cement and initiates communication with the formation. A single stage can contain up to 20 i-Frac sleeves, with one ball dropped to activate all the sleeves and isolate the zone for stimulation treatment. nov.com 

NOV The i-Frac sleeves are ball-drop-activated multistage frac sleeves designed for cemented, multiple open/close and openhole horizontal completions. (Source: NOV)

Perforating gun system increases safety
Schlumberger’s Tempo instrumented docking perforating gun system is the industry’s first perforating gun system to fully integrate a plug-in gun with real-time advanced downhole measurements throughout the operation. This unique combination significantly mitigates operational risk while increasing safety, reliability and efficiency. By generating and confirming dynamic underbalance in the well, the Tempo system effectively removes perforation debris to optimize productivity. First-year deployments include North and South America, the Middle East, Europe and Asia. According to the company, excellent results have been achieved, from understanding the wellbore dynamics during perforation to achieving a 100% fires success rate on all guns deployed without any misfire. In Egypt an operator employed the Tempo system to improve the efficiency of multizone perforating operations in deep wells in the Western Desert. Conventional perforating gun systems had required significant operational time to assemble and arm, and their integrity could not always be verified until at perforating depth, at which point diagnosing any connection failures caused lengthy remedial downtime. The new plug-in gun simplified design saved considerable time, including reducing gun arming time by more than half. slb.com/tempo

Schlumberger Tempo The Tempo system fully integrates a plug-in gun with real-time advanced downhole measurements for monitoring and confirming operations to mitigate risk while increasing safety, reliability and efficiency. (Source: Schlumberger)

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Higher Demand For Perforating Systems Strains Supply Chain

With increased drilling rig efficiency and longer laterals, the horizontal environment has changed the nature of the perforating business.

PERFORATING SYSTEMS INDUSTRY UPDATE:

The zenith of the drilling rig count in the U.S. occurred on Dec. 28, 1981. There were 4,530 rigs in the U.S. drilling about 30,000 to 35,000 mostly vertical wells per year. On April 12, 2019, the rig count was 1,022 rigs. Even at that number, the industry is still drilling 30,000 to 35,000 mostly horizontal wells per year.

“I was a field engineer when I first started my career. I would go out and shoot maybe 10 guns per well. Today in a horizontal environment, we shoot 50 stages. We might shoot 10 guns per stage. We are shooting 500 guns in a well, an order of magnitude higher,” said George Patton, product development manager for the Owen Oil Tools division of Core Laboratories.

“One of the challenges for us is that we have to build more guns, more charges, more detonating cord, more detonators and more switches. For all the technology that has been around for decades, we have to be able to manufacture more than we have ever done in the past. At the same time, we need to be more cost effective.”

That demand for more equipment has led to other challenges. “Just the volume of the business is stretching the supply chain really thin,” said James Barker, Halliburton technical chief for perforating technology. “There are shortages in steel for the gun carriers and even explosive powders for the shaped charges. There have been significant shortages in those arenas over the last year, especially the explosive powders.”

That has led Halliburton to introduce new frac charges based on the explosive pentaerythritol tetranitrate (PETN). “That’s really a polymer-coated PETN for enhanced handling and safety. It was released in 2019,” he said.

The increased efficiency of the drilling rigs and the shift to longer laterals in horizontal wells have impacted perforating systems. “The whole horizontal environment has changed the nature of our business enormously. A lot of the ideas we used to accept in the vertical environment are being challenged in the horizontal environment,” Patton said.

Companies are also beginning to measure the efficiency of perforating systems with defects per million opportunities (DPMO). “The reliability has increased to about 99% or better, but even more is demanded. As the industry gets better and better, you kind of lose whatever 99.x% means from a success standpoint. If you cast it in DPMO, then it amplifies how good you really are,” Barker said.

While the sheer demand for perforating guns is straining the system, manufacturing companies continue to work with operators and service companies to improve the technology for perforating systems.

Consistency of hole size
With the advent of horizontal wells, what has really become a critical factor is the consistency of the hole size. In a horizontal well, the guns will sit on the low side of the casing. The perforation hole size can vary around the casing.

“You have one shot right next to the casing on the bottom of the casing. Then, you have a shot on the top of the casing that is going across the fluid gap between the gun and the casing. The performance of that charge is diminished. It is no longer what the API [American Petroleum Institute] specs are,” Patton said.

Frequently, the hole size consistency can be a 20% standard deviation with a standard conventional charge, he explained. “You might have an average 0.36-in. hole, but in the 6 o’clock position, the hole size could be 0.49 in. and 0.24 in. in the 12 o’clock position. We can change the shape of the jet that makes the perforation so we can get a hole size in all six positions around the casing down to a 3% standard deviation,” he said.

Owen Oil Tools’ consistent-hole-size charge is branded HERO PerFRAC, which is now its largest selling series of charges. This product line was initially introduced in 2014 and relaunched in 2016. Since then, the company has improved the standard deviation from less than 10% to less than 3%.

Owen Oil Tools The hole size consistency can be a 20% standard deviation with a standard conventional charge (right). Owen Oil Tools has improved its standard deviation from less than 10% to less than 3% (left). EH stands for the entrance hole diameter of the casing.
(Source: Owen Oil Tools)

“We have talked to the operating companies about their specific casings because hole size varies for each casing size, weight and grade. The gun sizes may change if you have large or small casing. We’ve brought in clients, and they have given us samples of their casing. We shot those at Owen Oil Tools’ facility in Godley, Texas. We demonstrated what we say about consistent hole size is true. They have used them in their wells and gotten better results, lower frac pressures, fracs being put away and even better production,” Patton said.

Another product being rebranded is the company’s ZERO 180 Perforating System, which is now being called Pinpoint Perforating System. This orients the gun downhole in a horizontal well. Society of Petroleum Engineer papers have documented that an operator should shoot in the 12 o’clock and 6 o’clock positions for the best frac performance.

“We have a tool that orients downhole in a horizontal well so you can shoot in any direction that you want,” Patton said. “We’ve got people who want to shoot in three directions—at 12 o’clock, 10 o’clock and 2 o’clock. That is very client specific.”

Another aspect of the Pinpoint Perforating System is avoiding fiber-optic control lines running down the outside of the casing with costs of about $1 million each on an average horizontal well. You have to be able to determine where the control line is. There are some logging tools and techniques to determine this. Once you know where they are, you can design your guns to shoot away from them,” he said. The company has had success in 2017 and 2018 with several wells in Canada that use control lines.

Wireline-conveyed pump-down technologies
The gun systems for plug-and-perf operations to support hydraulic fracturing in the shale fields are getting better and better, Halliburton’s Barker said. “By that I mean premiums are now placed on things like fast turnaround time, efficiency at the well site and reliability so that you minimize idle time for the frac pumps,” he said.

“Trying to get the DPMO number better just drives you to be better in your gun designs where the parts come together quicker and easier for our field organization to assemble. That has led to our company being one of the pioneers in loaded guns from the manufacturer. We can load guns here in a controlled environment at the shaped-charge plant and ship loaded guns to the districts,” he continued.

For this type of market, the industry is still trying to determine what the optimal perforating design for their frac is. “The trend now seems to be shorter guns with fewer shots per cluster but [to] have more clusters per stage. What might be eight to 12 clusters per stage may now be around 20 clusters. Even as I say the trend is toward shorter guns, we just had some orders come in for longer frac guns with 15 to 18 shots. I think the jury is still out with the production and frac pumping companies themselves,” he said.

The propellant suppliers are getting into the schemes as well by enhancing the perforation with some overpressure from a propellant. “Some of these are now being tried in the field to see if that helps lower breakdown pressures and makes more efficient fracs at the well site,” he said.

Coated PETN does alleviate the safety concerns. There are powder shortages with the traditional explosives that are used every day in the oil and gas industry—RDX (cyclotrimethylene trinitramine) and HMX (cyclotetramethylene tetranitramine).

“PETN, if it is not manufactured properly, can be a more sensitive explosive. Our introduction is a polymer-coating that covers the crystals of the explosive, which brings its sensitivity to the RDX and HMX levels,” Barker said. “What we see is no real clear winner. Maybe there never will be. There is always some wrinkle from field to field or area to area. But there is a broad product offering right now. There seems to be no universal gun system such as the six shots, 60-degree phasing. There are other options.”

Tubing-conveyed perforating, testing
For tubing-conveyed perforating systems, there is a trend toward larger diameter gun systems—the 6½-in. and 7-in. gun systems for offshore work with high shot densities of larger explosive quantities. This technology is still being requested by customers.

“What is new technology is the modeling software for job design because you are looking at two things. When you shoot those big guns, how do you make sure you’ve optimized your production through controlling the dynamic underbalance and other geomechanical considerations of the formation?” Barker asked. “Because of the large explosive contents, you also have to make sure that structurally your guns are protected from collapse and parting, and that you don’t corkscrew the tubing or unseat the packers. There are now quite a few advancements made in the modeling software that predict both what is happening in the reservoir and how you protect your perforating gun string and completion string from damage.”

The last item involves testing that is specifically available in the flow laboratories.

“The industry has known for a long while that it is doing a good job of directing the industry in perforator penetration prediction. API 19B uses concrete targets shot on surface. Folks have now realized that is not really telling the true picture,” he said. “People are now beginning to realize that this also applies to the hole diameter that is produced in the casing. We’re beginning to see now that this is a much more complex mechanism than was envisioned previously when using hole-size predictions about what happens behind the casing based on surface-condition targets. Instead, those shots need to be done under simulated wellbore conditions if you want to have an accurate representation of what is happening.”

Tests at the Halliburton Advanced Perforating Flow Laboratory Tests at the Halliburton Advanced Perforating Flow Laboratory are designed to provide a measure of the flow performance of a perforation into a stressed rock, simulating reservoir-specific downhole conditions. (Source: Halliburton)

Manufacturing challenges
Owen Oil Tools has had to gear up its manufacturing operations and improve the technology in manufacturing, including the techniques the company uses to manufacture because it needs to be more cost effective, Patton said.

“Operating companies are coming to us now wanting us to build thousands of guns instead of tens of guns. They want us to be able to do it cheaper than what we could for tens of guns. We’re automating our manufacturing processes more than we have ever done. We’re using robotics more,” he said. “The whole manufacturing operation is changing dramatically. The demand for Owen products is greater than it has ever been. We sell millions of charges every year and hundreds of miles of guns. We need to be very efficient in services that we provide in perforating for those companies to bring oil and gas to the worldwide community at an effective price.”

One of the manufacturing challenges for Owen Oil Tools is that historically it has not had relationships with the operating companies. “One of the things we’ve been doing the last couple of years is spending more time and talking directly with the operating companies concerning the value that we bring to their operations,” Patton said.

The company does not want to lose its relationship with the service companies that distribute its products to the operators, but they are spending more time with the operating companies. “That was something we didn’t do 20 years ago. But we give them a lot more today by working directly with the operating companies while maintaining relationships with our historical clients,” he said.

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More shale water solutions:

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Companies Focus On Replacing Freshwater Sources

Technology for reusing flowback and produced water offers solutions for regions facing limited water sources and drought.

 

 

With the market for water management technology, handling and solutions expected to grow from about $8 billion in 2019 to more than $10.5 billion in 2026 by various estimates, service companies and midstream water providers are vying to supply the infrastructure, processes and equipment to meet operators’ needs for water treatment and transportation.

Midstream water companies are installing both permanent and temporary pipelines throughout unconventional shale plays in efforts to reduce the number of trucks hauling water. The number of water treatment facilities and water hubs is growing in shale plays with limited surface water availability.

With increased seismicity in several areas, such as the Scoop/Stack and Mississippi Lime in Oklahoma and the Permian Basin, companies are placing more emphasis on managing saltwater disposal wells while maintaining the disposal capacity needed by the industry.

The Permian Basin is one of the basins facing a shortage of surface water. Service companies and water midstream companies emphasize the reuse of produced and flowback water as a major solution.

The following companies are representative of some of the key players in water management and their approach to meeting oil and gas industry demand.

Aquatech Energy Services
With a total water system for sustainable upstream oil and gas water treatment solutions that are based on end use for the water, Aquatech Energy Services (AES), a division of Aquatech International, has been providing services on a turnkey basis to operators of both unconventional shale and conventional wells to manage, treat for reuse, and dispose of drilling, flowback and produced water.

The company also uses biocides and disinfectants to treat source and produced water for sulfate-reducing bacteria, reduction of H2S and prevention of biofilm formation within storage tank batteries. Source, flowback and produced water are treated for iron and manganese to reduce hardness-bearing compounds, such as barium, calcium and magnesium, and to reduce sulfates. 

The AES team has extensive field experience, mostly in the Marcellus Shale play. The aim of the company is to develop solutions that ensure consistent water composition with minimal contaminants for predictable production characteristics in hydraulic fracturing and also minimal downhole scaling. For example, its MoVap mobile distillation system is designed for removal of total dissolved solids to produce ultraclean water, which will help reduce wastewater volume.

The AES treatment processes are based on technology from Aquatech International. Business options range from short-term to long-term contracts operating at well pads using mobile treatment units or at central facilities using fixed modular treatment units, according to the company’s website.

Its systems include the MoSuite system for producing reusable and sustainable water sources for multiple well pads as well as for reducing the volume of freshwater. The MoTreat mobile pre-treatment system removes total suspended solids and also can treat for hardness, bacteria and select precipitation of metals. AES operates multiple merchant central water treatment facilities serving producers for treating and disposing of wastewater from E&P activities.

Aqua Terra Water Management
Aqua Terra Water Management partnered with De Nora Water Technologies to provide a one-stop shop for produced water management. The company combined its disposal and pipeline transportation infrastructure with De Nora’s water treatment technologies to create a fixed-facility recycling option.

“By leveraging Aqua Terra’s extensive existing infrastructure and vast experience in disposal facilities with De Nora’s technologies, the market now has an efficient and inexpensive solution for the transportation, disposal and recycling of their produced water,” a July 9, 2018, press release stated.

“De Nora has always prided itself on having the environment at the core of its business values,” said Bryan Brownlie, managing director at De Nora Water Technologies Texas LLC. “Working together with Aqua Terra provides a sound solution for mass recycling in some of the most water-challenged areas in the U.S., including the Permian Basin.”

De Nora is a designer of safe and sustainable water disinfection and oxidation, filtration and electrochlorination solutions.

Aqua Terra’s goal is to provide solutions by providing expertise and strategies that meet regulatory and environmental requirements, according to the press release.

Aqua Terra CEO Cory Hall said, “When the drought hit in 2011, the use of freshwater became a serious issue throughout the Permian Basin. As the fracking processes become more advanced, our team has looked at and evaluated many different recycling techniques. Through our research, we have concluded De Nora’s process is best in class, which allows us to offer our customers a reasonably priced, effective substitute for freshwater for their fracking operations.”

According to the press release, “Recent recycling conducted by Aqua Terra Water Management utilizing De Nora’s process at Aqua Terra’s Jaker facility resulted in 98% reduction of iron, 100% bacteria kill, 100% removal of H2S and an 80%-plus reduction in total suspended solids, capable of producing excellent quality frac fluid with one unit able to treat 100,000 barrels per day.”

Baker Hughes, a GE company
Baker Hughes, a GE company, Well Chemical Services help protect the integrity of wells while maximizing production before, during and after fracturing operations. Customized solutions are designed to avoid fracturing water challenges with superior water analysis and treatment while improving productivity with a customized flow assurance program.

The H2prO SR water management service uses a mobile system with proven filtration technology to remove suspended solids from produced and flowback water. It returns up to 99.9% of the water for reuse in hydraulic fracturing and other oilfield operations. The operator can conserve freshwater, reduce transportation and disposal costs, and ensure regulatory compliance, the company stated on its website.

The mobile H2prO SR service is more flexible, providing an economic solution compared to permanently installed equipment. Each filtration unit can treat up to 10,000 bbl/d of water and is simple to set up. It has a low energy consumption rate, which lowers overall operating expenses. Each unit has a small footprint and requires no special permits to transport, so the units can be deployed quickly to meet any time schedule, the website said.

The H2prO HD well chemical service uses environmentally preferred chemistry to treat produced and flowback water in tanks, reserve pits, impoundments and ponds. Using proven chlorine dioxide technology, the service neutralizes microorganisms, H2S, iron sulfide, phenols, mercaptans and polymers in the surface water. The water can be reused for downhole operations with no threat of corrosion and equipment plugging, according to the website.

The H2prO HD service has a fast chemical reaction time, concentrated solutions and high chlorine dioxide generation rates. A single, mobile unit treats up to 200,000 bbl/d of water. The H2prO HD well chemical service includes pre- and post-water testing to ensure conformance to water quality standards, the company’s website stated.

Basic Energy Services
Basic Energy Services’ network of fresh and brine water stations, particularly in the  Permian Basin where surface water is generally not available, is used to supply water necessary for drilling and completion of oil and natural gas wells.

The company’s water logistics segment provides oilfield fluid supply, transportation, storage and disposal services required in workover, completion and remedial projects as well as in daily producing well operations, according to Basic’s website.

With service locations positioned in major basins to support a wide range of drilling programs, Basic provides trucking and water hauling expertise through 1,000 trucks manned by experienced, trained drivers. In addition to water treatment services for recycling water, the company also offers rental of portable frac tanks and test tanks for storing fluid at the well site.

The company’s water logistics assets include specialized tank trucks, portable storage tanks, water wells, frac tanks, test tanks and saltwater disposal (SWD) wells.

Basic provides fluid services through fluid supply, transportation and storage services using a fleet of more than 800 fluid service trucks supported by portable storage tanks, water wells and disposal facilities, the company said.

For water recycling, Basic provides efficient and environmentally responsible water recycling services featuring the chlorine dioxide process, the website noted. Basic’s Water Recycling Services group provides environmentally friendly water treatment services that efficiently recycle water, reducing the number of trucks needed for offsite disposal while
increasing productivity. The Water Recycling Services group complements the Pumping Services and Fluid Services water hauling and SWD services, providing a complete range of options for water management needs, according to the website.

As part of its commitment to the environment, Basic uses a fleet of LNG-powered trucks primarily for water hauling, the company noted.

 

Blackbuck Resources
With operations across New Mexico, Texas and Oklahoma, Blackbuck Resources LLC (BBR) designs, builds and operates water infrastructure and provides water-related services to the oil and gas industry.

The company’s infrastructure division provides produced water gathering and disposal systems while the energy services division offers treatment of produced water for reuse as well as transfer services.

BBR also boasts the only full-service pond management offering, utilizing an advanced aeration system and remote water quality monitoring alongside physical sampling and corrective remediation, according to the company.

On July 12, 2018, Xedia Process Solutions announced it was acquired by Blackbuck Resources LLC. BBR will be led primarily by the prior Xedia management team and will be supported by an equity commitment from Cresta Energy Capital. With Xedia’s water treatment experience and technology, BBR has a “competitive advantage” in providing E&P companies with “a one-stop shop” for water treatment, transfer, storage and disposal, a press release stated.

Xedia functions as a wholly owned subsidiary of BBR, offering its water treatment products to E&P operators globally, while BBR provides Permian Basin E&P operators with treatment services and water infrastructure.

In the press release, former Xedia and current BBR CEO Justin Love said BBR will continue to improve and expand its ability to tackle the energy sector’s toughest water challenges by leveraging a growing team and pool of expertise and its existing footprint as a technology-enabled treatment service company.

Blackbuck Resources water management

 

Cudd Energy Services
To deliver custom-engineered systems to address water management challenges in oilfield operations, Cudd Energy Services’ Water Management Solutions (WMS) group provides water treatment, water recycling, biocide services and well remediation. These systems offer a cost-effective method for managing onsite fluid supply, treatment and pit circulation, according to the company’s website.

The WMS technology is designed to provide flexibility in setup configurations while improving personnel safety and operational efficiencies. These systems allow easy mobilization, rapid rigup capabilities and seamless integration with a variety of remote control and automated features, the website noted.

The company’s personnel plan and implement its systems to improve operational efficiencies and mitigate risks. WMS provides the optimal treatment plan and configuration to meet water needs safely and efficiently.

The water treatment system consists of a contained, mobile unit that restores produced water for reuse in oilfield applications by eliminating bacteria from fresh, produced and recycled water sources. The system reduces solids content, removes hydrocarbons, breaks down emulsions, accelerates iron removal and destroys H2S in produced water, according to the website.

Compartmental units are housed on individual trailers that can be rapidly mobilized to centralized pits, tank batteries and water collection/treatment facilities. Produced water may be transported to the treatment area or extracted from tank batteries or existing pits, the website stated.

The biocide treatment system treats produced water, surface water, surface vessels and wells for bacterial control. The biocide treatment system also includes oxidizing treatments to control iron sulfide, eliminate H2S, remove biomass and biofilm, break emulsions and control other oxidizable species.

This system uses Petro-Flo Microbiocide, a fasting-acting biocide that effectively controls all types of bacteria. WMS performs onsite water testing to determine the optimal dosage to treat the particular water source.

De Nora Water Technologies Texas LLC
De Nora offers energy-saving products and water treatment solutions, serving many industries with diverse applications. With technologies and processes for the filtration, oxidation and disinfection of water and wastewater, De Nora has been addressing the offshore and onshore water treatment needs of the oil and gas industry for decades, from proven solutions in biofouling control, sewage treatment and membrane filtration on offshore drilling platforms to onshore frac water disinfection, produced water recycling and oil refinery process water treatment. De Nora offers a comprehensive portfolio of proven water treatment solutions for the oil and gas market’s water challenges.

Bryan Brownlie, managing director at De Nora Water Technologies Texas, said, “By working with our oil and gas partners, we’ve demonstrated that we can produce results with market-beating economics, not just for produced water recycling, but also for frac water disinfection—without the safety risks inherent to the use of chlorine dioxide in an enclosed trailer.”

DistributionNOW
For fully customized modular design, DistributionNOW (DNOW) U.S. Process Solutions, which includes Power Service, Odessa Pumps and Total Valve Solutions, can provide customized skid package engineering, design, fabrication and installation services for water management needs. The packages have integration technology so that a unit can operate completely automated.

For offshore and onshore oil and gas operations, the company provides saltwater disposal (SWD), waterflood, water transfer and custom-engineered packages. Its filtration systems are available for fresh and produced water transfer skids, custom SWD packages, chemical injection skids and waterflood packages, according to the company’s website.

Pumps are offered from several manufacturers, including Schlumberger’s Reda HPS horizontal surface pumps, NOV/Moyno positive displacement and progressive cavity pumps as well as Griswold and Flowserve ANSI B73.1 pumps. Equipment is selected for the best fit for the application.

For 60 years Power Service has designed, engineered and fabricated SWD and waterflood packages.

With multiple packaging options, DNOW Process Solutions can customize the operator’s facility whether it is an open unit with a small reciprocating pump or a large facility with multiple horizontal multistage pumps. Control logic allows modulation of the facility’s flow. An operator can inject into multiple wells at varying pressures from a single injection pump and can adjust to surges in incoming rates, the website stated. The packages can be designed for injection rates up to 60,000 bbl/d and pressures up to 5,000 psig, stated the website.

Whether by pipeline or truck, the company’s extensive knowledge of hydraulics, fabrication and automation ensures that the operator’s facility will provide reliability.

Dow Water & Process Solutions
With a wide range of water treatment technologies, Dow Water & Process Solutions offers the technical expertise to treat water produced by shale gas and oil extraction via hydraulic fracturing techniques, according to the company’s website.

Dow specializes in removing the organic compounds and harmful metals from flowback and produced waters before reuse or discharge. The company’s ion exchange and DOWEX OPTIPORE polymeric adsorbent technologies are used to remove the metals and organic compounds such as benzene, toluene, ethylbenzene and xylene.

The company’s TEQUATIC PLUS fine particle filter is a new technology that can be used to help filter difficult-to-treat waters with high total suspended solids. The filter proved successful in applications such as produced water disposal wells by reducing the maintenance and consumables costs compared to traditional technologies such as cartridge and bag filters, the website stated.

Operators are finding opportunities by applying an integrated approach that uses advanced technologies for oil and gas. For example, BNN Energy helped an operator reduce water sourcing costs and environmental impact by integrating TEQUATIC PLUS Filters into its system. The operator has since increased the volume of recycled produced water to almost 100% and expects to save about $2/bbl of water, reducing operating costs by about 60% (results may vary depending on specific operating conditions), according to the website.

With its DOW FILMTEC reverse osmosis and nanofiltration elements, operators can manage shale gas-produced water. Another nanofiltration membrane is Dow’s FILMTEC SR90 Elements, which are designed to selectively remove sulfate from seawater used for waterflood injection operations in offshore oil production, helping prevent barium and strontium sulfate scale precipitation. This nanofiltration membrane operates efficiently at lower pressures and removes all particles greater than 0.001 μ, which results in injection water free of silica and bacteria, the website stated.

Evonik
Evonik develops advanced chemistries that enhance production, protect assets and increase value throughout the hydrocarbon life cycle.

PERACLEAN 15 from the Active Oxygens Division is an ecofriendly, Environmental Protection Agency-approved antimicrobial used to treat flowback and produced water. Unlike nonoxidizing biocides, it acts rapidly to destroy acid-producing and sulfate-reducing bacteria. It also can oxidize reduced sulfur species (e.g., sulfide). PERACLEAN 15 leaves no toxic residue, as the product decomposes to water, oxygen and CO2.

Evonik polyoxycarboxylates and DEGAPAS products are aqueous polymer solutions with excellent dispersing properties. These anionic polymers, free of nitrogen and phosphorous, interrupt inorganic crystal growth and are perfect antiscalants/dispersants. They are optimized to prevent scaling based on calcium, magnesium, iron or manganese salts.

VISIOMER methacrylate monomers provide excellent building blocks for high-molecular-weight cationic flocculants for water treatment. A new application area is extended-release scale inhibition.

The Technical Applications Product Line offers a comprehensive series of cationic and nonionic surfactants. The ADOGEN, TOMADOL and TOMAMINE lines include fatty amines, etheramines, amphoterics, alcohol ethoxylates and amine quaternaries. These products are ideal for emulsifying and stabilizing the components of oilfield formulations, such as drilling fluids, stimulation fluids and corrosion inhibitors.

Evonik signed an agreement in November 2018 to acquire PeroxyChem, which manufactures peracetic acid and hydrogen peroxide. The transaction is scheduled to be completed by mid-2019. For the oil and gas market, PeroxyChem offers hydraulic fracturing biocides and viscosity breakers, oil sands processing and EOR.

Evonik Evonik’s advanced chemistries enhance production, protect assets and increase value throughout the hydrocarbon life cycle. (Source: Evonik)

Evoqua Water Technologies
Evoqua Water Technologies offers water treatment solutions for both onshore and offshore oil and gas industry operations.

With more than 40 years of experience in delivering projects to the offshore market, Evoqua understands the strict regulations and requirements with which the industry needs to comply.

To protect the lifetime of equipment, “Chloropac systems can save oil producers over 5% of lost production by reducing biofouling of heating and cooling systems,” according to the company’s website. “These systems are used by 75% of leading operators to keep their field assets working efficiently.”

Evoqua is also the preferred provider for BOP fluid management systems to some of the largest offshore drillers in the industry, according to the company. Evoqua provides an Offshore Rig Water Solutions line of standard products for the management of critical fluids for its BOP systems.

Over the last five years, the company has deployed dozens of systems for continuous operation in the toughest environments, the website stated.

In addition to more than 100 years of experience in water treatment and purification, Evoqua has more than a decade of experience developing high-purity water treatment specifically for BOP applications, gaining a thorough understanding of the drilling rig environment as well as the industry’s rigorous standards and certification processes.

Fountain Quail Energy Services
Fountain Quail Energy Services seeks to help operators reduce water management costs by integrating the company’s industry expertise with exclusive treating and recycling systems.

The company’s water treating and recycling systems—SCOUT, ROVER, MAVREX and NOMAD—are technologies being used by operators in all shale plays, having assisted in cutting water-specific operating costs by at least 30% and up to 80%.

Fountain Quail’s highly mobile SCOUT system targets suspended solids, oil, iron and bacteria.

The ROVER technology targets the same contaminants as the SCOUT, but each ROVER system is semi-mobile and capable of recycling greater than 30,000 bbl/d to 105,000 bbl/d of clean brine, depending on location. Fountain Quail will customize a ROVER solution for long-term projects.

The MAVREX system utilizes variable feedback controlled chlorine dioxide technology and is effective across a broad range of bacteria and biofilms. Chlorine dioxide is less corrosive than bleach or ozone and has less of an impact on frac chemistry than peracetic acid.

The NOMAD technology employs the most energy-efficient thermal evaporator available in the market. The skid-mounted system made by Fountain Quail engineers is capable of generating 2,000 bbl/d of distilled, surface-discharge quality freshwater.

Fountain Quail owns, operates and is developing an expanding portfolio of Class II saltwater disposal wells that serve the Marcellus and Utica shale plays.

Fountain Quail’s MAG Tank is a modular, aboveground containment solution that provides operators with a flexible, customizable footprint, multiple capacities and a solution that significantly reduces truck traffic.

Fountain Quail water management Fountain Quail designed the mobile SCOUT system for suspended solids, oil, iron and bacteria. (Source: Fountain Quail Energy Services)

Goodnight Midstream
By building, owning and operating produced water infrastructure in the prime oil shale fields in the U.S., Goodnight Midstream has a leading position in the Bakken Formation, a rapidly expanding footprint in the Permian Basin and Eagle Ford Shale, and an emerging presence in the Powder River Basin, according to the company.

According to a November 2018 press release, Goodnight Midstream announced it expanded its revolving credit facility to $420 million from $320 million to fund continued strategic growth initiatives in the Permian, Bakken and Eagle Ford shales as well as support working capital requirements.

In 2018 Goodnight Midstream completed and is now operating 15 new saltwater disposal (SWD) facilities across the basins in which it operates. The company expects to complete construction on five additional facilities in early 2019.

In the Permian Basin, Goodnight Midstream recently completed and is operating two high-pressure, trans-basin systems, the Llano and the Rattlesnake pipelines, serving several long-term contractual customers. This infrastructure will transport the increasing amount of water expected out of the Delaware Basin to the depleted fields of the Central Basin Platform.

For SWD, Goodnight Midstream is able to create tailored, long-term solutions for its  customers. The company now owns and manages a network of more than 45 gathering and disposal facilities connected to more than 420 miles of produced water pipelines on redundant systems, offering greater than 99% uptime for its customers, according to the company.

GR Energy Services
GR Energy Services offers operators technology-driven water management solutions using a unique horizontal pumping system (HPS) that drives gains for saltwater disposal, injection and water management. The versatile system provides advantages to inject or transfer at higher volumes and pressures and to reduce operating costs by eliminating common issues faced by water logistics managers.

The Flex Flow water management system integrates field-proven multistage centrifugal pumps with variable speed drives, surface controls and automated reporting capabilities to lower the total cost of operations. The trailer-mounted systems can be deployed very quickly as cost-effective options for early commissions, step-rate tests or replacement of equipment under repair.

The Flex Flow HPS can be monitored remotely to make adjustments that optimize system efficiency. Digital, cellular and satellite enabled, the programmable logic controller can report to mobile devices and computers with multiple notification options. The system requires little maintenance, so uptime is optimized and service callouts are kept to a minimum.

GR performance advisers can tailor both permanent and trailer-mounted Flex Flow HPS systems to a wide range of operating conditions with flow rates up to 100,000 bbl/d of fluid. Surface facilities engineers using Flex Flow systems have documented lower maintenance and repair costs, longer runlife and greater operating flexibility and efficiency, according to the company.

GR Energy Services GR Energy Services’ Flex Flow HPS was designed for saltwater disposal, injection and water management. (Source: GR Energy Services)

Gradiant Energy Services
Gradiant Energy Services offers custom-engineered solutions and technologies for oil and gas operators seeking safe, reliable, economic, environmental and efficient treatment, reuse and recycling of flowback and produced water.

Gradiant’s Selective Chemical Extraction (SCE) is a mobile water treatment process that provides reusable clean brine as hydraulic fracturing fluid. By cleaning water only to the needed level—and not beyond—the SCE process enables the reuse of treated produced water for operations, according to the company’s website.

The company can transform the most difficult water makeup into the highest quality freshwater with its Carrier Gas Extraction (CGE) technology.

“Developed at the Massachusetts Institute of Technology [MIT], CGE desalinates oilfield wastewaters to produce extremely freshwater (less than 500 ppm and even lower in many cases) and a highly concentrated brine solution that can be utilized for drilling, workovers and completions,” the website noted. “CGE reduces the high transportation costs of produced water by treating the wastewater on site, producing freshwater and saturated brine.”

CGE also can be used to generate a concentrated, 10-lb brine that can be used for drilling, workover and completions applications.

Gradiant’s Free Radical Disinfection technology “provides high-volume disinfection treatment to control bacteria and treat water for storage pit maintenance, on-the-fly disinfection prior to hydraulic fracturing operations and pre-saltwater disposal injection” and also reduces H2S in water, according to the website.

The company’s Carrier Gas Concentration (CGC) technology, developed at MIT, “is ideal for E&P operators in remote areas that have disposal constraints, high trucking and disposal costs or the need to enhance evaporation rates in ponds and pits,” the website stated. “The CGC process involves evaporating water and concentrating dissolved solids in the wastewater stream via a multistage bubble column humidifier.”

Gravity Oilfield Services
As increased drilling activity and high-intensity well completions drive the need for high volume water sourcing, transport and disposal, Gravity Oilfield Services provides infrastructure and logistical expertise to be the single-source supplier on which operators can rely.

With decades of expertise, deep resources, a large fleet of vehicles and high-performance equipment, Gravity has an expansive footprint in the major oil and gas producing basins, particularly in the Permian Basin. Its network of fluid logistics assets and infrastructure includes fresh and brackish water production and storage pits, long-life delivery, produced water gathering, freshwater sourcing pipelines, fluid hauling trucks and saltwater disposal (SWD) wells.

Gravity operates more than 125 miles of permanent pipeline infrastructure capable of managing water needs throughout the life cycle of a well along with an extensive fleet of fluid service trucks and containment solutions. There is also an extensive inventory of more than 5,000 fracturing and mud tanks for every fluid containment need.

The company has an extensive network of strategically located SWD wells in the Permian Basin and Williston Basin. Gravity has several water-sourcing agreements with operators in the Permian Basin and is taking additional commitments.

In June 2018, Gravity acquired McKenzie Energy Partners LLC. McKenzie provides contracted midstream-based water management solutions for some of the most active operators in the Bakken Shale play through a network of produced water gathering pipelines and water disposal wells situated on core acreage dedications, according to the acquisition press release.

Gravity Oilfield Services Gravity Oilfield Services offers fresh and brackish water production, storage pits, produced water gathering, freshwater sourcing pipelines, fluid hauling trucks and SWD wells. (Source: Gravity Oilfield Services)

H2O Midstream LLC
H2O Midstream partners with producers, land owners and other stakeholders to improve the efficiency, reliability and safety of water operations while lowering costs across the value chain.

The company owns and operates the Permian’s only truck-free, third-party produced water hub and pipeline network consisting of 1 MMbbl of storage and 265,000 bbl/d of permitted disposal capacity from 13 disposal wells, all interconnected via 150 miles of pipeline.

In addition, the company has removed more than 350,000 truckloads per year of produced water from Texas roads.

H2O Midstream owns and operates integrated water infrastructure, including gathering pipelines, storage, treatment, disposal and reuse facilities in the Permian Basin. The company continues to expand its existing system through additional infrastructure to serve the needs of multiple producers in the area.

H2O Midstream was selected by the University Lands (UL) management group to handle water across its 167,000 acres in the Delaware Basin. UL manages the surface and mineral interests of 2.1 million acres of land across 19 counties in West Texas for the benefit of the Permanent University Fund.

In partnership with Layne Water Midstream, a new University Lands Water Management LLC (ULWM) was formed to service UL’s produced and source water needs in the Delaware Basin.

H2O Midstream is funded via a private-equity commitment from EIV Capital and co-investments from several of EIV’s institutional partners collectively representing more than $70 billion in assets under management.

H2O Midstream LLC H2O Midstream owns and operates the Permian’s only truck-free, third-party produced water hub and pipeline network. (Source: H2O Midstream)

Halliburton
Halliburton has the processes, tools and expertise to responsibly and cost effectively address all water challenges. With more than 1,500 consultants and 5,000 chemists, engineers and scientists, the company provides the upstream E&P industry with expertise and analysis to assist in a variety of water management challenges from surface to subsurface, according to the company’s website.

Halliburton’s use of conformance processes often can improve an operator’s profitability as a result of the following benefits: longer productive well life; reduced lifting costs; reduced environmental concerns and costs; minimized treatment and disposal of water; and reduced well maintenance costs. Halliburton’s EquiSeal Conformance service was specially developed to shut off water production in horizontal or highly deviated wells.

Halliburton can help minimize the use of freshwater in the oil field during drilling and completion of a well, fracturing or thermal operations. For stimulation, Halliburton’s Excelerate friction reducer portfolio was designed to perform exceptionally in produced water, across a broad range of salinity. Additionally, the polymers within the friction reducer portfolio were built with rapid hydration for quick performance and structured so operators can pump less material for reduced residue compared to competitive offerings.

Halliburton water management Halliburton’s Conformance chemical portfolio helps reduce unwanted fluid production to efficiently enhance hydrocarbon recovery. (Source: Halliburton)

Hillstone Environmental
Founded in 2015, Hillstone Environmental operates in the Permian Basin, Williston Basin and Marcellus/Utica Shale play providing comprehensive water infrastructure solutions. These services include designing, building, owning and operating water pipeline to disposal as well as providing water treatment, recycling and reuse. The company’s fully integrated water midstream solution allows it to “maximize operating efficiency, reduce costs and reduce environmental footprint,” the company stated on its website. The company’s systems include 24/7 SCADA monitoring and leak detection.

Hillstone’s water pipeline and disposal system in Loving County, Texas, has a total throughput capacity of 480,000 bbl/d across an interconnected network of pipelines and disposal wells, according to the company. Hillstone’s interconnected system in Loving County allows the company to gather, transfer and dispose of produced water across its entire system and manage through spikes or unplanned outages, which the company said “gives customers certainty that their produced water will be disposed of reliably, safely and without interruption.”

The company also has treated more than 100 MMbbl of water in the Permian and Marcellus/Utica. Hillstone’s coagulization process involves using mobile treatment units, each with up to 20,000 bbl/d of treatment capacity, and the process integrates into existing client operations and can be done concurrently with drillout and flowback.

Hillstone Environmental Hillstone’s Cleveland saltwater disposal facility, which is interconnected via pipeline to its other disposal assets, is located in Loving County, Texas. (Photo by Tony Gutta, courtesy of Hillstone Environmental) 

Hydrozonix
To reduce risk and operating cost by optimizing water quality and use throughout the frac water cycle, Hydrozonix offers consulting, technology and services, and works with oil and gas companies to design and implement comprehensive, cost-effective water management programs.

The company’s end-to-end approach includes assessment to ongoing operations and maintenance.

Hydrozonix water treatment technology uses mobile and permanent systems that are ozone-based and require no liquid chemicals as well as portable aeration systems that maintain the quality of stored flowback and produced water.

The company provides “advanced technologies separately or as part of its HzO Trio program, which can replace conventional chemical programs and provide more effective control of bacteria, iron and sulfide at a much lower cost,” according to the company’s website. Hydrozonix has saved operators 60% to 90% over the cost of liquid oxidizers.

The HzO Trio includes HYDRO3CIDE, an automated oxidation system for produced and flowback water; a portable Hydro-Air Aeration System that aerates and mixes water in storage pits and tanks to maintain water quality; and On-The-Fly oxidation systems that disinfect water and remove iron and sulfides without chemicals that can be incompatible with frac fluids.

“Operators that recycle with the HzO Trio combination achieved higher water quality for a fraction of the cost of chemical programs,” the company stated on its website. The HYDRO3CIDE platform includes a dashboard that monitors systems performance and water quality in real time on a PC or cellphone. 

This year Hydrozonix is rolling out HYDROFLARE, a flare-gas fired evaporator, and HYDROPOD, a buoy that measures water quality in pits and tanks and sends data via cellular signal for real-time capture. “Together our systems provide a comprehensive program for low-cost produced water management from recycling to disposal,” the company said.

Hydrozonix HYDRO3CIDE is the Hydrozonix automated oxidation system for produced and flowback water that includes a dashboard that monitors systems performance and water quality in real time on a PC or cellphone. (Source: Hydrozonix)

Keane Group
Since every system begins with the base water to be used on the job being tested, Keane Group offers recommended custom solutions that are cost-effective for the customer in terms of operations
and production.

The company’s ReLease ReUse produced water fluid systems are effective in all produced water scenarios, including 100% produced or flowback water. Where the cost of freshwater has an economical limitation, ReLease ReUse enables operators to continue operations with reduced cost and logistics associated with treating produced or flowback water, according to the company’s website.

Keane has systems for slickwater, linear gel and both borate- and zirconium-crosslinked gels, which allow operators to run produced water at any hardness, pH, mineralogy, temperature or salinity level.

Additionally, ReLease Speed is a full line of slickwater systems with friction reducers, which are economically customized for stimulation using either cationic or anionic freshwater solution. Options for high-brine applications also are available, the website stated.

The company also offers ReLease Dry, which is a dry friction reducer alternative that reduces spill risk.

Keane’s ReLease Linear fluid systems are natural or modified natural polymers used without crosslinkers that provide an economic fluid option without compromising viscosity characteristics. Polymers used include guar, carboxymethyl cellulose or cellulose gum, and carboxymethyl hydroxy propyl guar.

In the SPE-172811-MS paper’s abstract, Keane discussed its Stabilized Crosslinked Fracturing fluid systems, which were pumped in the Permian Basin, using borated produced water with levels of total dissolved solids exceeding 30,000 mg/l. The systems are designed to delay the crosslinking time when needed, utilizing the boron already present in the water. This frac fluid system approach has broken the code for recycled water and reduced disposal costs, according to the company’s website.

Key Energy Services
Saltwater disposal wells allow Key Energy Services to handle produced fluids responsibly and efficiently. Key operates more than 60 Class II disposal injection wells, where produced water is run through settling tanks prior to injection, according to the company’s website.

Key’s fluid management services include transportation of fluids used in the drilling and completion process as well as frac flowback and produced water from completed or producing wellbores.

For managing fluid levels within its tank systems, the company equipped its disposal wells with a computer-controlled system for receiving produced water. The facilities are designed to treat and filter water efficiently, therefore injecting the cleanest possible water into disposal wells.

Its 50-plus wells are permitted for a combined 15 MMbbl per month. The company has four permitted fresh and brine water facilities throughout the Permian Basin, each providing more than 1,500 bbl/d, the website noted.

“Significant growth in water volume per completed well is driving total freshwater and flowback water demand. Continued growth in water volumes employed on a per-well basis drive water transfer demand,” said Robert Drummond, Key president and CEO, in a March 2018 presentation.

Key’s energy production solutions and services are provided through its experienced crews, technical expertise, data analytics and fit-for-purpose equipment, according to the company’s website.

The company’s vacuum trucks transport nonhazardous fluid or waste to or from well operations. The materials commonly carried include freshwater, field saltwater, 10-lb brines, calcium chloride/bromide, water and oil-based muds and other drilling fluids. 

Layne Water Midstream

As a full-cycle water midstream business, Layne Water Midstream (LWM) provides upstream oil and gas companies with water sourcing, disposal and recycling services in the Delaware and Midland basins.

LWM was founded as part of Layne Christensen Co., a 135-year-old global water management company. Today LWM operates a growing produced water management and disposal business in the Delaware Basin with existing pipelines, disposal assets and numerous in-process saltwater disposal (SWD) permits that are soon expected to provide more than 400,000 bbl/d of transportation and disposal capacity.

The company also operates an extensive source water business in the Delaware Basin with its 26-mile, 175,000-bbl/d Hermosa pipeline and access to source water in more than 90,000 acres in Reeves and Culberson counties in Texas, either owned by LWM or under long-term, exclusive lease arrangements.

LWM also operates water infrastructure assets in the Midland Basin, including more than 100,000-bbl/d source water assets in Martin County, Texas, and existing SWD permits.

The company’s business includes contracts with landowners for water midstream services on nearly 300,000 acres in the Permian Basin, including an exclusive long-term contract with the Texas General Land Office (covering 88,000 acres in Reeves and Culberson counties) and a preferred water services provider contract with University Lands (covering more than 160,000 acres in Ward, Winkler and Loving counties).

MYCELX Technologies Corp.
MYCELX Technologies Corp. provides advanced solutions for produced, process and wastewater challenges primarily in the oil and gas sector. The company’s polymer has oleophilic and hydrophobic characteristics and is designed to meet the industry’s toughest water treatment requirements.

MYCELX permanently binds with oil and hydrocarbons through the process of molecular cohesion. The company’s engineered solutions offer superior hydrocarbon removal with a smaller footprint and a lower cost to treat. 

As environmental regulations and operational challenges increase across the globe, the need for MYCELX’s water treatment expertise has been recognized by a growing group of industry leaders including Chevron, BP, Anadarko, Schlumberger, SABIC and SNF Floerger, according to the company.

The company will consistently deliver water to specifications chosen by the client and can ensure discharge of less than 1 ppm oil in water if required. The produced water can be safely discharged and meets regulatory standards set by the U.S. Environmental Protection Agency, U.S. Coast Guard, Saudi Arabian Royal Commission Environmental Regulations and Nigerian Department of Petroleum Resources.

The company has designed standardized equipment for its patented media and can undertake primary, secondary and tertiary stages of water treatment for customers. By combining these coalescers, backwashable media vessels and polishers, MYCELX is able to create robust tailored solutions. Systems can handle variable flow rates from 25 gpm to 5,000 gpm.

A single MYCELX system can easily handle high flow rates of up to 120,000 bbl/d, and given its smaller footprint, it is possible to scale up easily to meet whatever flow is required. The flexibility of the company’s engineered systems make them ideal for a wide range of applications and deployments, particularly offshore drilling platforms. 

MYCELX RE-GEN, which is the company’s backwashable media, offers the necessary step-change improvement in water treatment capability that is critical for companies focused on EOR and are hampered by conventional water treatment technology’s limitations.

Oilfield Water Logistics
In the midstream water infrastructure and services industry, Oilfield Water Logistics LLC (OWL) has a focus on pipeline gathering systems, produced water disposal and produced water reuse services.

OWL primarily operates in the Permian Basin, including both the Midland and Delaware basins.

The company has additional assets in the Rockies region, including the Powder River Basin, Wamsutter and Piceance, as well as in East Texas. 

OWL owns and operates the largest produced water gathering system in the northern Delaware Basin and Lea County, N.M. OWL recently completed its Red Hills Water Gathering System pipeline expansion project, which extended its Lea County system into Loving County, Texas. The connection provides access to upward of four additional saltwater disposal wells and numerous new customer connections.

In the Rockies, OWL recently expanded its Thunder Basin facility in Converse County, Wyo., to meet the increasing water management demand in the Powder River Basin.

OWL’s extensive midstream water infrastructure networks offer E&P companies the opportunity to reduce water sourcing and disposal capex while providing redundant systems to effectively handle the industry’s growing water needs, according to the company’s website.

By building supply and gathering lines, as well as reuse infrastructure where appropriate, OWL’s customers are able to maximize efficiency and minimize water management costs.

OSP
OSP, a service and supply company, works with the global oil and gas industry to create solutions for the effects of water and its use. For water treatment, OSP provides microbial testing technology as well as oilfield chemicals, including microbial and scale inhibition products, and water-focused consulting services.

OSP’s 2K7 Bugstick is a solid stick biocide that enables delivery to inaccessible areas where microbes can proliferate, the company said. The company’s biocide is available in several formats and formulations depending on the application.

In 2011 the acquisition of Telomer Corp. expanded OSP’s oilfield chemical products to include scale inhibition, providing chemistries and finished formulations that effectively target scale issues.

In 2017 OSP expanded its service offerings to include microbial identification and evaluation, offering molecular testing, including DNA qPCR and 16S sequencing. “Understanding you can’t mitigate what you can’t measure,” OSP provides the technical services and technology, on site or in the laboratory, to target and test for microbial contamination to achieve microbial control, the company stated on its website. OSP targets, tests and treats microbial-related issues such as corrosion and souring.

Pentair
To provide petroleum producers, refiners and gas processors dramatically improved solids control and hydrocarbon recovery from process water streams, Pentair offers its hydrocarbon recovery technology (HRT) for produced water management, oil removal from wastewater and saltwater disposal.

HRT eliminates the need for expensive excess processing, chemical additives and storage tank capacity. Hydrocarbon recovery efficiencies of 99.98% are available through HRT, according to the company’s website. HRT’s design is scalable and modular for both new capital projects as well as placement in existing operating units.

Benefits to using HRT on process water systems include operational flexibility, reduction of lost energy, savings on chemical additives, lower maintenance costs associated with fouling, and elimination of excursions, the website noted.

Pentair recognizes that produced and flowback water streams must often be treated prior to disposal, reinjection or reuse, and that the capital and operating costs associated with most treatment systems can be very high.

The company provides high-performance filtration and separation systems for produced and flowback water streams that will lower operating and capital costs and add value. The company offers a broad array of secondary water treatment technologies that allow the reuse of produced-water streams for uses such as agricultural irrigation and boiler feed water, according to the website.

Pentair’s Pure Pack system is a portable solution for secondary and tertiary produced water and wastewater treatment, offers superior water quality with a smaller footprint and lower cost of ownership, the website stated. With oil content as high as 5% to 10% at the inlet, the Pure Pack can yield low ppm oil at the outlet. The high-quality recovered oil may be processed or sold to add value to the operator, the website noted.

ProSep
By providing solutions that meet or exceed regulatory and/or other operational requirements, such as reinjection and EOR, ProSep’s produced water treatment system helps operators manage and treat produced water streams. The company’s technologies include TORR, CTour Process and Osorb Media Systems.

The company’s produced water treatment portfolio includes primary, secondary and tertiary treatment options, which can be supplied as individual process units, integrated plug-and-play packages or as complete produced water treatment solutions.

ProSep’s Osorb Media Systems (OMS) utilize the next-generation adsorbent, Osorb Media, for efficient water treatment/polishing. Osorb Media is a regenerable, organically modified silica specifically designed to remove dispersed, dissolved and emulsified hydrocarbons from produced waters, according to the company’s website.

The simple, integrated OMS water treatment systems allow operators to remove benzene, toluene, ethylbenzene and xylene (BTEX); light to heavy crude oil; gas condensate; and some oilfield chemicals to less than 1 ppm. The systems maintain their efficiency in a broad range of applications, including the removal of hydrocarbons from CEOR polymer flood operations.

The TORR coalescing technology has a small footprint and the ability to replace less efficient oil removal equipment. It is a modular, scalable technology that addresses future increases in water cut for offshore operators. The process consists of two or more in-line pressure vessels and an optional spare vessel to be used as standby.

ProSep’s CTour process removes dispersed oil and dissolved hydrocarbon contaminants in the produced water stream through injection of condensate. The process routinely yields residual oil discharges of less than 5 ppm total petroleum hydrocarbons, while at the same time removing 80% to 95% of harmful water soluble organics, such as BTEX. The process is used extensively in Norway, having treated as much as 70% of all Norwegian offshore produced water. This equates to more than 2 MMbbl/d of water.

Purity Oilfield Services
With a complete line of water solution services, Purity Oilfield Services can coordinate setup and disposal as well as handle all other logistics for water service needs for completion services and other operations.

The company’s growing operational footprint includes the Permian Basin as well as South Texas, the Rocky Mountain regions and Canada.

With its diversified portfolio of rental items, trucking services, water services and strategic distribution alliances, Purity offers the flexibility of daily rentals to turnkey package solutions. The company provides services for drilling, completion, production and midstream operations.

Purity has five core divisions: the Water Transfer Division with 10-in. and 12-in. layflat pipe with the associated pumps and equipment; the Blue Line Division, offering a variety of tanks and aboveground storage tanks for water storage, consisting of 20,000-bbl, 40,000-bbl and 60,000-bbl ponds, frac tanks, uprights, bins, open tops and more; the Trucking Division, which consists of trucks capable of transporting freshwater and brine water and supporting the move of oilfield equipment and other oilfield trucking needs; the OFT Well Testing Division, which offers a fleet of well-testing units and services for flowback and well testing services; and the recently added Pure Heat Division that offers a new method to heat water at the well site or transfer source for completion services.

Purity’s freshwater services can be provided with turnkey pricing on services and rentals on a single well site or an entire field. The programs allow the operator to control expenses by knowing the project costs upfront.

Purity Oilfield Services Purity Oilfield Services coordinates and handles all logistics for water service needs for completion services and other operations. (Source: Purity Oilfield Services)

Reclaim Water Services
Reclaim Water Services’ solution nonchemically removes contaminates from the water. Reclaim will provide nondetectable levels of hydrocarbons and bacteria and iron less than 1 ppm. Other solutions use dangerous chemicals to change the water chemistry and leave the contaminates in the water. This requires contaminant cleanup somewhere down the road. The treated water can be reused as soon as the system is discharged.

The system offers the following advantages: no retaining/settling ponds required, cleans water more completely than other processes, water is ready to use within 8 hours of entering the system, remote operation offers greater safety with less manpower, costs are competitive with all other processes, and units handle from 3,000 to 40,000 bbl/d and can be combined for larger volumes, according to the company.

Reclaim Water Services Units are designed for volumes from 3,000 to 40,000 bbl/d and can be combined to meet higher demand. (Source: Reclaim Water Services)

Samco Technologies Inc.
For onshore and offshore applications, Samco Technologies Inc.’s oil and gas solutions include a cooling tower water treatment, boiler feed water treatment, wastewater treatment and zero liquid discharge.

Based on its technologies, Samco’s customers “have experienced increased oil recovery, cost-effective injection-water treatment, superior separation and destruction of acid/sour gas, expanded plant productivity, increased process uptime, cost-effective waste reduction and industry-compliant discharge,” according to the company’s website.

In addition to treating produced water for washing crude oil, Samco has developed a seawater desalting solution that performs directly on the platform, using a filtration process that then uses membranes to separate sulfates from the water, the website noted.

To effectively wash the light crude, the seawater is filtered to remove suspended solids and sulfates. It then uses its two-step process for oxygen removal. Samco’s two-step oxygen removal process is a method of removing oxygen from water down to extremely low levels. This method can be particularly useful in offshore EOR, the website stated.

When performing EOR offshore, a lot of water can be brought up with the oil. Samco developed a procedure to remove the water from the oil, recover the oil and safely discharge the water back into the ocean from onboard the platform or recycle it for reinjection.

Schlumberger
Schlumberger offers various services for managing the complete cycle of water management. The company’s experts have a thorough understanding of stimulation fluid requirements, operational schemes, reservoir characteristics, production volumes, hydrogeology, engineering design and environmental considerations.

Schlumberger’s AllSeal water and gas conformance service controls or shuts off unwanted water or gas production with an engineering approach. Schlumberger’s FracCON water-conformance fracturing fluid within the AllSeal water and gas conformance service was developed for high-water-cut wells with recoverable reserves near oil-to-water contact or gas-to-water contact. It features a relative permeability modifier capable of producing enhanced fracture geometry and increased proppant pack conductivity while mitigating water cut after fracture stimulation treatments, according to the company.

In addition, the company’s xWATER integrated water-flexible fracturing fluid delivery service is designed to reduce or eliminate freshwater use and its associated transportation and disposal costs, while also decreasing environmental impact, according to the company. “The service enables operators to use an engineered fracturing fluid customized for the available water, well conditions and reservoir properties—saving on the water-related costs that can account for up to 25% of the total operation cost,” the company stated on its website.

Schlumberger water management The Schlumberger AllSeal service integrates chemistry, geology, operations, economics and logistics to reduce or eliminate water and gas production for a particular well or field. (Source: Schlumberger)

Select Energy Services Inc.
Select Energy Services Inc. provides oilfield water management services, including water sourcing, water transfer, containment, water treatment, flowback and well testing, fluids handling, and disposal across all major U.S. unconventional basins. Select’s water sourcing services identify, acquire and permit source water to assist operators with water acquisition, storage, evaluation and regulatory handling. The company has about 1.5 Bbbl of water available for operator use in hydraulic fracturing.

Select’s water transfer services are provided through a variety of mobile hose, piping and automated pumping systems to support hydraulic fracturing. The company’s water transfer services include pipe and pump selection, frac support, filtration and flowback support.

AquaView is a suite of technologies developed by Select to remotely monitor and control water assets and provide real-time data, including volume and water quality, all accessible 24/7 through the Aqua- View computer, smartphone and tablet applications. AquaView automated pumps and proportioning systems respond to operator specifications and changing conditions in real time with the ability to remotely set and maintain operational parameters.

For containment, Select offers high-volume aboveground storage tanks, reusable secondary containment systems, tank pedestals, in-ground and surface mount wall steel containments, heating and liners.

Select’s water treatment services utilize a wide spectrum of bio-control, aeration and recycling technologies to prepare source water or tie flowback and produced water back into frac supply for reuse. Additionally, Select has permitted disposal facilities located in the major U.S. shale plays with a permitted capacity of more than 300,000 bbl/d.

Through its Rockwater Energy Solutions brand, the company manufactures and supplies oilfield chemicals to optimize fluids during completion and production. Tidal Logistics is the in-house fluids handling service line that provides fluid recovery and removal, production support and storage.

Select Energy Services Select’s Aquaview system includes automated pumps that give remote and timely visibility to water supplies as well as the ability to self-adjust transfer rates to match other equipment in the system. (Source: Select Energy Services)

SitePro
SitePro, a digital oilfield solutions provider, develops real-time, cloud-based software designed to optimize the management of the full water life cycle. The company offers services for producers, disposal and recycling, water midstream, and water sourcing.

For water sourcing, SitePro offers an alternative to manually checking pond levels, turning on water  wells, turning valves and allocating volumes with its remote-control technology, turnkey automation and custom software interface.

SitePro’s new Water Sales Monitoring technology allows users to monitor frac ponds, storage pits and transfer lines in real time and control pumps and valves remotely from a computer or mobile device.

“Our volume allocation and ticketing services complete the life-cycle solution for service companies looking to lower their operating costs and reduce downtime,” the company said on its website.

The volume allocation feature allows users to easily differentiate water volumes from various operators, storage pits and truck sales for accurate and efficient billing and tracking. The technology also allows users to remotely control water wells from their phone or desktop, turning valves on or off based on level or volume set points. 

For disposal and recycling, SitePro offers services for saltwater disposal (SWD) wells that provide total asset management, merging remote control, monitoring and automation with electronic ticketing and invoicing. The company helps operators partially or completely eliminate the need for field personnel. SitePro’s turnkey automation and software products cover every aspect of an SWD facility or system of facilities, including electronic ticketing, access control and flow measurement, surveillance, tank level monitoring, fluid conditioning, pipeline volume allocation, wellhead monitoring, cloud-based reports and regulatory reporting, and advanced analytics.

SitePro water management With SitePro’s Water Sales Monitoring technology, ponds and storage pits can be viewed and controlled remotely, and the remote control technology eliminates the need to dispatch personnel for pump or valve control. (Source: SitePro)

Solaris Water Midstream
Solaris Water Midstream owns, operates and designs water infrastructure assets with a current focus in the Permian Basin. The independent company’s services include produced and flowback water gathering and transportation, wastewater reuse and disposal, water sourcing and delivery, and pipeline design and operation. 

The company’s currently operating water infrastructure systems are located in the Delaware and Midland basins. Solaris’s Pecos Star System in the Delaware Basin has more than 200 miles of active and under construction permanent pipelines transporting produced water and supplying recycled and brackish water for oil and gas operations. The Pecos Star System’s pipeline network is connected to numerous active and under construction disposal wells. Solaris is currently permitting additional wells and pipelines. By the end of the year, the system will have more than 400 miles of large diameter produced water and water supply pipelines and connections to dozens of owned and third party disposal and recycling facilities across Texas and New Mexico. Additional systems are under development in the Delaware Basin, which will have similar service offerings as the Pecos Star System.

Solaris Water’s Midland Basin systems include about 85 miles of pipelines, two recycling facilities capable of recycling 25,000 bbl/d each and connections to 11 disposal wells.

Solaris Water Midstream Solaris’ DJK saltwater disposal well is located in Midland County, Texas. The site also serves as an integrated reuse facility. (Source: Solaris Water Midstream)

Sourcewater Inc.
Sourcewater is a geospatial water intelligence platform and water marketplace for the upstream  energy industry. Sourcewater gathers oilfield business activity data from its online water marketplace, which has more than 5,000 water and saltwater disposal capacity listings in the Permian Basin. The company gathers these data from satellite imagery computer vision analytics, which detect and measure every frac water impoundment and well pad in the Permian Basin every five days, matching each feature to surface and mineral ownership and operator lease.

The company also gathers data from state government regulatory filings for oil, gas, water and disposal wells as well as treatment facilities; parcel and mineral ownership records and leases; continuous market research; and Internet of Things and SCADA sensor partnerships to obtain real-time water and disposal levels, flows and pressures from the field. Data are gathered, cleaned, normalized, structured, analyzed and visualized through advanced geospatial mapping tools, custom research reports and an API for larger users.

Sourcewater recently acquired the assets and intellectual property of Digital H2O, enabling Sourcewater to gather and show the oil, gas and water production of every oil and gas well in Texas, New Mexico, North Dakota and Pennsylvania as well as show disposal well capacity, pressures and utilization for all of these states. In Texas Sourcewater shows the logistical relationships and flows between every commercial disposal and every operator lease.

Sourcewater Sourcewater’s Water Asset Intelligence platform shows the monthly capacity utilization of every disposal and injection well in Texas, New Mexico, North Dakota and Pennsylvania going back to 2013. It also shows the hydrocarbon and water production of every producing lease and maps exactly where each lease sends its produced water for injection and disposal. (Source: Sourcewater)

TETRA Technologies Inc.
TETRA Technologies’ water management services for hydraulic fracturing and unconventional well completions include sourcing, fresh and produced water transfer, pipeline construction, storage and pit lining, treatment and recycling, blending and distribution, and flowback and testing, all of which are automated and remotely monitored.

The company’s water treatment services are “fully automated and integrated to help meet operators’ increasing water requirements by recycling, treating and delivering an optimized fluid for frac operations—all while yielding significant cost savings and reducing operational and HSE risks,” according to the company’s website.

TETRA uses an oil separation system to accumulate and remove residual oil from produced water in real time to ensure treatment performance and compliance with regulatory storage requirements. The accumulated oil can then be put back into the operator’s sale pipeline. In several cases, the volume of reclaimed oil has almost paid for the use of the system.

The company uses an automated water treatment system to chemically treat produced water through a clarification process that enables recycling of up to 50,000 bbl/d of produced water with a single system. Custom systems are built to handle larger volumes. The system uses web-based, real-time monitoring and control technology providing operators with 24/7 access to treatment and recycling operations. This provides a transparent and on-demand view on the chemistry applied to treat the water and its effectiveness. 

TETRA also offers automated blending and distribution technology that provides accurate parameter-based blending and consistent blend quality, whether directly filling frac tanks or transferring to another location. The technology is equipped with real-time, computer controlled, tank-level management ensuring supply and preventing tank overflows.

The company’s storage and U.S. Environmental Protection Agency-compliant pit lining services ensure drilling and completion operations have a sufficient water supply on site and on demand.

TETRA Technologies Inc. This illustration shows TETRA Technologies’ fully automated and integrated water management solution that includes sourcing, fresh and produced water transfer, pipeline construction, storage and pit lining, treatment and recycling, blending and distribution, and flowback and testing for hydraulic fracturing and unconventional well completions. (Source: TETRA Technologies)

Veolia Water Technologies
Veolia provides water treatment, reuse and wastewater services and technologies. Its water treatment technologies include more than 350 solutions to manage, optimize and recover water and wastewater for municipal and commercial systems. The company’s focus is on increasing and extending the value of water and wastewater resources.

ShaleFlow is a transportable, modular system that utilizes proven technologies to treat up to 10,000 bbl/d (300 gpm) of produced water with a simple drop-and-go approach.

The company’s CoLD crystallization process for desalination of produced water is designed to eliminate the need for expensive pretreatment of the produced water, thereby reducing capital and operating costs, according to the Veolia.

In addition, Aquavista is the company’s new digital services platform that offers a wide range of customized digital solutions for water treatment systems.

Veolia ShaleFlow is a mobile solution for produced water reuse. It is a transportable, modular solution that utilizes proven technologies to treat up to 10,000 bbl/d (300 gpm) of produced water with a simple drop-and-go approach. (Source: Veolia)

WaterBridge Resources LLC
WaterBridge Resources LLC, a portfolio company of Five Point Energy LLC, provides producer-focused water management solutions through integrated pipeline networks for produced water, transportation, disposal, supply and recycling. 

WaterBridge owns and operates more than 1.3 MMbbl/d of produced water disposal capacity throughout the Southern Delaware Basin and Arkoma Basin that are connected by more than 450 miles of pipeline.

WaterBridge recently acquired assets from and entered into a long-term produced water management contracts with Concho Resources Inc. and Halcón Resources Corp., both in the Southern Delaware basin. Including these transactions, WaterBridge has approximately 285,000 dedicated acres under long-term contracts with 19 producers in the Delaware Basin and approximately 182,000 dedicated acres under long-term contracts with three producers in the Arkoma Basin.

WaterBridge water management A WaterBridge produced water handling facility is located the Southern Delaware Basin. (Source: WaterBridge Resources LLC) 

Water Standard/Monarch Separators
Water Standard builds and delivers water treatment solutions and services to the global energy industry. The company specializes in compact modular membrane and ultrapure water systems and mobile onshore and offshore facilities. They offer flexible contract options for products and services ranging from specialized engineering and design to the supply of turnkey and rental systems.

Water Standard’s subsidiary, Monarch Separators, designs, engineers and manufactures separation technologies for removal of oil and solids from produced water and wastewater in the energy industry.

Together, the companies provide products and services that allow energy companies to safely and responsibly reuse their water as an asset and/or discharge it back into the water cycle. For example, their H2O Spectrum platform technology provides operators with a wide spectrum of produced and flowback water treatment options, including disposal, recycle and reuse, and treatment for safe surface discharge.

The companies’ combined expertise in water treatment applications include waterflooding, IOR and EOR; produced and flowback water treatment; desalination, sulphate removal and/or softening; membrane deaeration; filtration; ultrapure water; mobile units; and fixed facilities. Additionally, the company’s water treatment technologies for discharge or disposal are designed to improve oil and water separation, treat EOR emulsions and minimize footprint and storage requirements.

Water Standard Monarch Separators Monarch Separators designs, engineers and manufactures separation technologies for removal of oil and solids from produced water and wastewater in the energy industry. (Source: Water Standard/Monarch Separators)

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Technology Reduces Produced Water By 50%

Proppant-bonded technology reduces formation water without hindering oil and gas production.

Produced or formation water is by far the largest byproduct of the oil and gas industry. Estimates show that for every barrel of oil recovered, 4 bbl to 10 bbl of formation water also are produced.

Formation water often contains salts, bacteria, organic chemicals and other contaminants. This can make the handling of formation water problematic. Most formation water is disposed of by injecting it into subterranean wastewater disposal wells; however, the added cost of hauling the water can severely impact well economics. Some companies treat the water for reuse in hydraulic fracturing or agriculture. Likewise, water treatment for reuse is not always an economical option.

The storage, transport, treatment and disposal of wastewater accounts for 89% of water management costs. The U.S. upstream industry was estimated to spend $34.7 billion on water management in 2018. Over the life of an individual well, produced water costs can total as much as $6 million. This represents nearly half of a well’s operating expenses, and these costs are predicted to increase.

Restrictions
Many states in the northeastern U.S. have tight restrictions on wastewater disposal, prompting higher associated transportation costs to neighboring, less-restrictive states for production water disposal. In Oklahoma additional restrictions have been placed on disposal wells due to water reinjection and seismic activity correlation. These restrictions limit the rate at which water can be reinjected and, consequently, increase costs associated with water management.

While efforts to manage fracturing flowback and produced water continue, little attention has been focused on limiting water production by addressing the issue downhole. Current technologies, such as gels or swelling chemicals, can limit formation water production, but they also restrict hydrocarbon flow. 

Hexion developed the AquaBond formation water reduction technology, which has reduced produced water by as much as 50% without hindering oil and gas production. The technology is bonded to the proppant, making its water-reduction properties effective for the life of the well. With the application of this technology, the costs associated with wastewater management can be reduced, leading to a lower cost per barrel of oil equivalent.

How it works
This advanced technology alters the relative permeability of the proppant pack to admit hydrocarbons and reduce the admission of water. Proppant coating functional group modification results in a tailored critical surface tension that is hydrophobic as well as oleophilic. This creates an impelling force that admits oil while restricting water flow through the proppant pack.

A test apparatus was developed by Hexion to demonstrate the technology’s preference for flowing hydrocarbon over water. The testing device consists of a bonded proppant core, attached to a tight-fitting rubber cap, encased in a reservoir cell. The rubber cap is affixed to a tube that extends from the reservoir cell and empties into a graduated cylinder. The reservoir cell is filled with oil and water, submerging the core. A vacuum pump pulls the fluid from the reservoir cell through the proppant core. The fluid is collected in the graduated cylinder, and the water-oil ratio (WOR) that has moved through the core is documented.

The AquaBond technology proppant core was tested against a control sample of traditional resin-coated proppant. The reservoir cell was filled with a 2-to-1 WOR, submerging the core. Testing indicated the AquaBond technology core admitted less than 5% water without hindering hydrocarbon flow, and the control proppant core admitted approximately 60% water and less overall oil. Testing was repeated using various crude oil and formation water samples to account for North American regional differences in oil/water composition. Similar results were noted in corresponding tests.

The proppant pack is a porous medium, allowing water to flow through the pack when oil is not present. This prevents water blockage in the pack or at the formation surface/proppant pack interface. A 5-to-1 WOR was added to the test apparatus to demonstrate this. Only water was in contact with the proppant pack at the onset of the test. Once the test began, water flowed through the core until oil made contact with the core. Upon contact, oil preferentially flowed, leaving remaining water behind in the reservoir cell. When tested, traditional resin-coated proppant continued to flow water after oil contacted the proppant core, resulting in most of the oil being left behind in the reservoir cell.

Case study
A trial was conducted in the Granite Wash Formation in the Texas Panhandle to prove the effectiveness of AquaBond technology in the field. A 23% tail-in of AquaBond technology on 40/70 substrate was utilized on two horizontal wells. These wells were compared with 11 nearby offset horizontal wells. Three of the offset wells used a 23% tail-in of 40/70 traditional resin-coated proppant, and eight wells used 100% uncoated frac sand.

Each well had a true vertical depth of about 11,000 ft, with a lateral length of 4,000 ft, bottomhole static temperature of 180 F, and a total proppant volume of approximately 2.3 MMlb per well. 

Traditional proppant and the uncoated frac sand offsets performed similarly over the trial period.  Comparatively, AquaBond technology wells had a 30% lower water cut and a 43% reduction in average cumulative water production, with no observed impact to total fluid production.

Hexion average water cut case study The chart depicts the average water cut for AquaBond technology wells and offsets in the Granite Wash Formation. (Source: Hexion)

Using the technology
Lead-ins, tail-ins or total proppant designs can be utilized, depending on formation characteristics, desired water reduction and water issue severity. The technology also can be used as a remedial treatment for existing high-water-cut wells.

The technology can be pumped downhole using the same method as traditional proppant. Frac water returns to the surface per typical flowback procedure. Hydrocarbons and formation water then come in contact with the proppant pack. The technology preferentially flows hydrocarbons over water, and more hydrocarbons (and less water) are produced to the surface.

This has been demonstrated in laboratory tests using an array of samples in varying WORs from numerous regions throughout North America. The Granite Wash case study demonstrates how this technology can reduce the production of formation water without impacting total fluid production. The technology has been further proven in the Permian Basin, Bakken Shale and Haynesville Shale.

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new pipeline projects in the permian

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Wink to Webster Texas Pipeline

  • Companies: Plains All American Pipeline L.P. and Exxon Mobil, Lotus Midstream LLC

  • Capacity: 1 million b/d capacity

  • Projected In-Service: In-Service: Q1 – Q2 2021

  • More Info:https://winktowebsterpipeline.com/

 

Gray Oak

 

Cactus ii

 

Jupiter Crude Pipeline

 

Epic Crude Pipeline

 

 

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Permian Global Access Pipeline

  • Companies: Tellurian

  • Capacity: 2.0 bcf/d

  • Projected In-Service: 2023

  • More Info: http://www.pgap.com/

 

Gulf Coast Express

 

Permian Highway Pipeline 

 

Pecos Trail

 

Permian-Katy Pipeline 

  • Companies: Sempra LNG & Midstream, Loews/Boardwalk Pipeline Partners

  • Capacity: 2.0 bcf/d

  • Projected In-Service: Q3 2020

  • More Info: http://www.p2kpipeline.com

 

Whistler Pipeline

 

 

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Grand Prix Pipeline

 

Epic ngl Pipeline

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