REPOST: Thanks To Fracking, Natural Gas Supplies (Barely) Withstand ‘Polar Vortex’ Assault

Americans spurred a wave of demand for gas as they sought warmth due to “polar vortex.” This Forbes.com article has the details.

Tower for drilling horizontally into the Marce...

Image Source: forbes.com

The polar vortex gripping the nation has brought a crazy week for natural gas. On Monday the demand for gas nationwide hit a record 125 billion cubic feet as homeowners and power generators sought to burn as much of it as they could get to keep the cold at bay. In a normal early-January week the draw on natural gas inventories is about 170 billion cubic feet. This week, according to market watcher Bentek, the drawdown is expected to be on the order of 310 bcf — the most ever.

The record demand stretched supplies in the Northeast. In the New York region on Monday prices for natural gas reached a record $100 per mmBTU. This is natural gas we’re talking about, not gasoline or oil. A week before spot prices were on the order of $4.25 per mmBTU.

“On Monday the message was, ‘We need every molecule we can get,’” says one natural gas trader in Houston. The price shock was felt as far south as east Texas, where spot prices were up to $40.20 per mmBTU, nearly matching the record set back in 2004.

Natural gas utilities, which serve homeowners and small businesses, have the first call on gas supplies in times like this as they are required by regulators to maintain a supply cushion for in order to keep grandma from freezing to death. That meant some power generators in the Northeast got pushed out. There’s also anecdotal reports of coal-fired plants going offline because their coal slurries froze up. As a result, during the deep freeze, nuclear power made up a bigger portion of the power supply pie, while some generators had to resort to the emergency measure of firing up their boilers with heating oil. Very little oil is burned for electricity anymore because of the high cost. But this week, says Jack Weixel, research director at Bentek, “they were back to burning fuel oil because it was cheaper than gas.” When natgas is selling for $100/mmBTU, anything goes.

Ironically, on the day when homeowners and power generators were burning all the natgas they could get their hands on, some producers were shut out of the market. In the Marcellus shale region of Pennsylvania is got so cold that gas wells froze shut. And not only could these producers not get their gas into the anxious market, but because they have long-term supply contracts with customers, these companies were forced to buy gas at record prices to cover their obligations. “On the two days when they could have made the most all year, they weren’t selling, they were buying,” says the gas trader.

“There’s never been more demand, but it has been colder,” says the trader, and if it gets this cold again, say in late February or early March, it could eat through all the natgas in storage, potentially causing shortages for millions. “People would die.” Of course traders like to talk up their books. This one is long gas, and thinks we could see $5 per mmBTU this year, up from a current $4.30. (He suggests the average Joe can get long gas with the U.S. Natural Gas exchange-traded fund (NYSE:UNG).

Those level-headed guys at Bentek, a division of Platts, aren’t so concerned. Having entered the heating season with 3.7 trillion cubic feet of gas in storage, Weixel expects we’ll exit winter with 1.4 tcf left over. The basis for that confidence: despite record demand, the U.S. is also enjoying near-record natgas supplies. Gas production this week is running about 64 bcf per day. That’s down a touch from the record 66 bcfd from late last year, but up about 20% from a year ago. All thanks to shale gas fracking.

The only problem is when this record supply can’t get to the regions of record demand. What the Polar Vortex has taught us, says Weixel, is that the Northeast needs more natural gas pipelines. “It takes Herculean effort to put pipe in the ground in the Northeast,” he says, but if residents of the region insist on getting rid of nuclear and coal-fired power plants, they’re going to have to accept the need for more pipelines. “It’s like that research ship studying climate change that got stuck in the ice,” Weixel says. In the Northeast the attitude is “we don’t want you burying pipelines in our backyard — but dang it’s cold.

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REPOST: Why the Era of High Gas Prices Is Supposedly Ending Read more: Why the Era of High Gas Prices Is Supposedly Ending

 Energy Information Administration is positive about the continued growth in U.S. oil and natural gas production. But predicting the future of energy is still uncertain. This Time.com article has the details.

 

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Image Source: business.time.com

A federal report released this week forecasts that U.S. production of oil and natural gas will increase for decades to come. At the same time, all signs indicate per capita energy usage—especially in terms of fossil fuels—will decrease. What does this all mean in terms of prices at the pump?

This week, the Energy Information Administration released a report, the Annual Energy Outlook 2014, offering projections on energy production and usage through the year 2040. As my colleague Bryan Walsh summed up, the report predicts a long period when energy production within the U.S. will rise and individual energy consumption will fall. “Energy use per capita declines by 8% from 2012 through 2040 as a result of improving energy efficiency and changes in the way energy is used in the U.S. economy,” the report’s authors stated in a press release.

The average VMT by LDV—vehicle miles traveled by light-duty vehicles, a.k.a. cars—has been mostly flat for the past five years, and thanks to continually improving fuel efficiency in new cars, it looks like we’ll keep gassing up less down the road. According to the report:
The fossil fuel share of total primary energy demand falls from 82% of total U.S. energy consumption in 2012 to 80% in 2040 as consumption of petroleum-based liquid fuels falls, largely as a result of slower growth in LDV VMT and increased vehicle efficiency.

How does this play out in terms of prices paid by consumers at the gas station? Gas station prices follow the lead set by the wholesale rates of crude oil, and according to The Detroit Bureau, Charles Chesbrough, a senior economist with IHS Automotive, said, “We expect we’re going to see crude oil prices (continue to) fall for a while.”

Phil Flynn, a senior market analyst at Chicago’s Prices Futures Group, was even bolder in his view of the foreseeable future. “The era of high energy prices, or at least high gasoline prices, has come to an end,” he said, per the Christian Science Monitor.

Because the U.S. is becoming less reliant on foreign energy sources, the thinking is that we’re more insulated from the fallout of strife in the Middle East and other factors that tend to cause spikes in energy prices around the globe. Consumer gas prices are expected to still rise and fall due to many of the usual market forces—seasonal demand, refinery production issues, weather—but we’re a lot less likely to be subject to the kinds of sharp, sudden increases in gas prices that have periodically hit commuters and families in recent years.

Overall, experts seem to be saying that the average gallon of regular gasoline will sell for closer to $3, rather than the $4 or $5 once seen as inevitable, for quite some time.

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REPOST: In Oil and Gas Country, Water Recycling Can Be an Extremely Hard Sell

Recycling can simply be more expensive than using freshwater in fracking. Read the full story here:

Image Source: nytimes.com

MIDLAND — Standing on a sprawling ranch where drilling rigs, cranes and bobbing stripper wells form a makeshift skyline, Jimmy Davis is not thinking solely about sucking up oil. It is not the only precious liquid that is pumped from under the land that he manages.

“We’re trying to preserve what we have for future generations,” Mr. Davis, the operations manager for Fasken Oil and Ranch, said about collecting clean water. Though required in abundance for oil and gas production, it is increasingly hard to find in drought-scorched Texas, where water use by drillers has come under increasing scrutiny.

With that in mind, after lacing water with sand and chemicals to use during the process of hydraulic fracturing, or fracking, Fasken pipes more than 330,000 gallons of the resulting wastewater each day through an on-site recycling system. Negatively charged waste in the water reacts with positively charged ions in the metal pipes, so the undesirable materials settle out and leave clean water that can be used for another hydraulic fracture.

Fasken now recycles close to half of the water it uses for fracking, Mr. Davis said. But the process is still experimental. Recycling is a money-loser for the company for now, adding about $70,000 to the cost of handling the 1.9 million gallons of water needed for each hydraulic fracture.

As the drought continues to take its toll on resources, more companies are considering the long-term benefits of water recycling, and state officials are trying to make that transition easier. Despite that momentum, recycling is far from a mainstream practice among oil and gas drillers because of the associated costs and the prevalence of disposal wells.

For Fasken, Mr. Davis said, recycling is simply more expensive than using freshwater.

This is partly because Fasken can get fresh groundwater at virtually no cost under the 165,000 acres of ranch that the company owns, and an underground piping system takes it straight to the mineral well.

Most other operators pay relatively low prices for freshwater. Some estimates put its cost at just more than one cent per gallon, though Mr. Davis said he had heard figures as much as four times that amount.

What is more, Texas is home to about 7,500 active disposal wells, making it relatively easy and cheap for drillers to dispatch their waste. That is a stark contrast with Pennsylvania, home to the Marcellus Shale, where geography is unsuited for disposal wells. Energy companies there must either recycle the water or truck it to neighboring Ohio.

So it may not be surprising that recycling has not reached scale in Texas. Permit applications for oil field water recycling jumped to 13 from just one or two per year (regulators had so few they did not initially count them separately from other recycling projects) from 2011 to 2012, according to the Texas Railroad Commission, which regulates oil and gas activities. So far this year it has received nine.

No state agency tracks how much water is being recycled. The Dow Chemical Company recently said it had processed more than 245,000 barrels of water in South Texas’ Eagle Ford Shale, perhaps the state’s hottest new shale play. That amount would cover about five hydraulic fracturing operations if the drilling were done vertically; in the Eagle Ford, horizontal drilling is taking off, which requires as much as three times the water per frack.

There are probably more water recyclers than reflected in the permit numbers, however. The Railroad Commission recently exempted “mobile” recyclers, which can recycle water on or near a fracking site to avoid trucking the water long distances, from applying for permits. Water Rescue Services, which operates on Fasken’s property, is one such recycler, but such units are not always easy to set up.

“If you’re going across a bunch of different landowners, it is harder,” said Wes Williams, president of Water Rescue Services. Because Fasken owns a large swath of land, it does not have to seek a neighbor’s permission to truck water back and forth or install pipelines. In the Eagle Ford Shale, drillers tend to try their luck on small parcels of land in different areas. Water recycling is impractical because it means trucking water long distances between sites.

Many South Texas farmers and ranchers say their water wells have gone dry. Drillers and their regulators counter that drought and population explosion are at least as much to blame for a water shortage, saying that the oil and gas industry’s water consumption accounts for just 1 percent of statewide use. (In the Eagle Ford, however, drillers may account for as much as 20 percent of water use in some counties.)

Industry advocates say that as drillers settle into the Eagle Ford, water recycling will increase.

“Right now, everything is going in our favor,” said Brent Halldorson, chief operating officer of Fountain Quail Water Management, a recycler that has worked in North Texas’ Barnett Shale for about a decade. Mr. Halldorson said Devon Energy, one of his company’s clients, has reduced long water hauls — and their cost — by placing recycling equipment in the middle of its operations.

Policy makers are also helping to kick-start the practice. The Railroad Commission’s exemption of mobile recyclers is one example, and state lawmakers last year clarified that drillers would not be liable for mishaps involving wastewater that they have already handed off to third-party operators. Industry observers say the drought’s grip on Texas has prompted a shift in energy companies’ attitudes.

“People are starting to look at produced water as an asset rather than a liability,” Mr. Halldorson said.

Still, while water recyclers’ presence on oil fields is growing, it started not long ago at zero. And despite his optimism, even Mr. Halldorson admitted that today’s average drilling company probably spends on recycling just over 1 percent of its budget for total water use and disposal.

Recycling cuts down significantly on disposal and trucking costs, though it does not eliminate them. Mr. Davis, of Fasken Oil and Ranch, said that after each recycling operation, three to five trucks must carry and dispose of solid waste that is removed from the wastewater, such as boron, sulfates or even radioactive metals. A significant amount of water — about 500,000 gallons — is also needed to drill the initial mineral well, and recycling that “would take a lot of equipment and a lot of money,” he said.

The next driver for water recycling could reach beyond the oil and gas business. If recyclers could clean the water enough so it can be used for other purposes, the value could be enormous, said Amy Hardberger, an assistant professor of law at St. Mary’s University.

“We haven’t seen a market for it yet,” Ms. Hardberger said. “But I think it’s coming.”

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REPOST: Oil Rises, Gasoline Higher On Refinery Outages

Supply concerns affected the gas futures, according to this Rigzone.com article. Read more:

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Oil prices rose and gasoline futures hit a three-month high on Friday, fueled by spread trading and supply concerns.

A string of glitches at U.S. refineries and strikes at four Total refineries in France lifted U.S. RBOB gasoline futures 1.5 percent, and they touched the highest level since early September.

“We have strong demand going into the holiday. We’re expecting record holiday travel, so we’re going to use more gasoline,” said Phil Flynn, an energy analyst at Price Futures Group in Chicago.

Further support came as data showed the U.S. economy grew at its fastest pace in almost two years in the third quarter, signaling potentially stronger fuel demand.

Gains in international benchmark Brent crude outpaced those in U.S. oil futures. Market players said the narrowing in Brent’s premium to U.S. crude to $10 a barrel earlier this week had been overdone.

“The strength in Brent is tied toward pushing that spread out,” said Addison Armstrong, director of market research at Tradition Energy in Stamford, Connecticut.

Brent crude gained $1.48 to settle at $111.77 a barrel. The crack, or difference, between Brent crude oil futures and gasoline widened to a more than three-month high of $5.70 per barrel.

U.S. oil settled up 28 cents at $99.32 a barrel.

Speculators added bullish bets to their U.S. crude futures and options positions in the week to Dec. 17, the U.S. Commodity Futures Trading Commission said on Friday.

Brent prices were also underpinned by continuing disruption in Libya, where crude exports have dropped to 110,000 barrels per day (bpd) from more than 1 million bpd in July.

The OPEC producer is stepping up fuel imports as a mix of militias, tribesmen and civil servants demanding political rights, or a greater share of Libya’s oil wealth, have occupied several oilfields and ports.

Violence in South Sudan threatened to disrupt oil production in the two-year-old nation as fighting reached vital oilfields.

China National Petroleum Co, a leading oil investor in South Sudan, said on Friday it was evacuating oil workers from its oilfields to the capital, Juba.

(Additional reporting by Joshua Franklin in London, Manash Goswami and Florence Tan in Singapore; Editing by Dale Hudson, Peter Galloway, John Wallace and Bob Burgdorfer)

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REPOST: US High Court Rejects Oil Spill Contempt Case

The Supreme Court declined to review the appeals about the aftermath of the 2010 Gulf of Mexico oil spill. Read the details in the Rigzone.com article below:

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WASHINGTON, Dec 16 (Reuters) – The U.S. Interior Department will not be held in contempt over its actions in the aftermath of the 2010 Gulf of Mexico oil spill after the U.S. Supreme Court declined on Monday to review an appeals court ruling in the government’s favor.

The nine justices refused to hear an appeal filed by Hornbeck Offshore Services LLC, a drilling company subsidiary of Hornbeck Offshore Services Inc, and other businesses affected by a moratorium on deep sea drilling that the federal government imposed in May 2010. The federal appeals court ruling that overturned a federal district judge’s contempt finding remains intact.

In April 2010, the Deepwater Horizon rig, owned by Transocean Ltd and leased by BP PLC , exploded, causing 11 deaths and a massive oil spill.

The Interior Department’s temporary drilling moratorium was immediately challenged by the drilling industry, prompting U.S. District Judge Martin Feldman of the Eastern District of Louisiana to rule in June 2010 that the government could not enforce it.

Despite the court order, the moratorium remained in effect in a modified fashion until October 2010.

The following year, Feldman held the government in contempt for violating his order and said it must pay almost $530,000 in legal fees to the companies that challenged the moratorium.

In an April 2013 ruling, the New Orleans-based 5th U.S. Circuit Court of Appeals reversed Feldman’s ruling. It said that although the government had violated the spirit of his order, its actions did not technically violate it. The companies then sought high court review.

The case is Hornbeck v. Jewell, U.S. Supreme Court, No. 13-56.

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REPOST: East Africa exploration update

The Tultule-1 wildcat well in the South Omo will be plugged and abandoned as a dry hole. Read the details from this online article:

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Tullow Oil plc (Tullow) announces that the Tultule-1 wildcat well in the South Omo block onshore Ethiopia, has reached a total depth of 2,101 metres and will be plugged and abandoned as a dry hole. The well was targeting a reservoir section similar to the sands drilled in the nearby Sabisa-1 well where oil shows were encountered but these sands were not penetrated in Tultule-1. Gas shows were however recorded which reaffirm the presence of a hydrocarbon source in the region. The results of both the Sabisa-1 and the Tultule-1 wells will now be analysed to determine the future exploration campaign for the area.

The OGEC rig will now move to the Chew Bahir basin in Ethiopia to drill the Shimela prospect in the eastern portion of the South Omo block where new seismic has delineated a number of exciting new prospects, some of which have encouraging seismic amplitude anomalies.  The well is expected to spud at the end of the first quarter of 2014.

Tullow is the operator of the Tultule-1 well with a 50% interest along with partners Africa Oil (30%) and Marathon (20%).

In Kenya, significant exploration activity continues in Block 10BB with the Amosing-1 well currently drilling and the Ewoi-1 well expected to spud by the end of the year. Following the discoveries made at Etuko-1 and Ekales-1, preparations are underway to flow test the wells with results expected early in the first quarter of 2014.

Source: Tullow Oil plc

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REPOST: Statoil awarded exploration permit offshore New Zealand

Statoil may begin with their extensive dialogue process with New Zealand authorities, as it obtained exploration permit in the Reinga-Northland Offshore Release Area. Read more from this article

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Statoil has obtained 100% equity share in an exploration permit in the Reinga-Northland Offshore Release Area in the New Zealand Block Offer 2013.

The permit covers approximately 10,000 square kilometres and is located approximately 100 kilometres from shore to the west of New Zealand’s North Island, in water depths ranging from 1,000 to 2,000 metres.

“We are very pleased with the award, which is in line with the sharpened exploration strategy Statoil has pursued over the last three years. Safe and secure operations are our first priority as we proceed to explore the permit’s potential,” says Erling Vågnes, senior vice president for Statoil’s exploration activities in the Eastern hemisphere.

The work programme is designed to fully evaluate the prospectivity of the permit in a staged manner within the 15-year permit timeframe. Statoil is committed to collect new 2D seismic data and to undertake a multibeam seafloor survey with selected core samples within the first three years. Following an analysis and interpretation of this data, Statoil will decide on further steps.

“Health, safety and the environment (HSE) is always Statoil’s first priority. We will draw on our broad global experience in seismic data collection to secure safe operations offshore New Zealand,” says Vågnes.

Statoil will now enter into an extensive dialogue process with New Zealand authorities, and engage with a wide range of stakeholders in order to understand the local community, and ensure adherence with local regulations, customs and considerations.

“Statoil strongly believes in a good dialogue with the communities we operate in,” Vågnes says.

“New Zealand authorities have emphasised that Block Offer 2013 is an important step towards realising the potential of New Zealand’s oil and gas resources. We are glad that our bid was accepted and look forward to being a part of New Zealand’s next phase in oil and gas development.”

Source: Statoil

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