Category Archives: oil

2017 oil producer spending plans are up but well off 2013 and 2014

Chart: 2017 producer spending plans are up but well off 2013 and 2014

By JWN staff

March 16, 2017, 7:36 a.m.

http://www.jwnenergy.com/article/2017/3/chart-2017-producer-spending-plans-are-well-2013-and-2014/

  • Producers have announced capital spending plans of $28.64 billion for 2017, according to 58 companies tracked by the Daily Oil Bulletin.
  • While that would be up roughly 20 per cent on 2016 spending, it’s less than half the roughly $64.92 billion in capex for 2014 from 90 companies tracked by the Bulletin, and $50.93 billion from 91 companies for 2013.

oil spendng forecast 2017

8 signs of cautious optimism for oil

 

8 signs of cautious optimism at CERAWeek 2017

By Jackie Forrest

March 14, 2017, 6:37 p.m.

http://www.jwnenergy.com/article/2017/3/8-signs-cautious-optimism-ceraweek-2017/

heavy-oil

Last week the global energy industry gathered in Houston, Texas for the annual CERAWeek conference.

Compared to last year—when the price of oil was near US$30/bbl—the industry’s mood was cautiously upbeat. Here are eight major themes that dominated the discussion:

  1. Returning to cautious growth. After many quarters in the red, higher oil prices and lower costs are healing corporate balance sheets. As a result, companies are starting to generate free cash flow and increase spending.
    However, corporate leaders are not planning on returning to the overspending habits of a few years ago; priorities include spending within cash flow and reducing debt.
  2. Hoping for a higher oil price, but not planning for it. Most conference speakers believe that longer-term (perhaps in the early 2020s), the industry’s underinvestment will turn the oil price upward. In the meantime, corporate leaders are preparing their companies to survive and thrive in a lower price world.
  3. Break-even cost estimates move down, again. Thanks to cost cutting and innovation, oil executives assert they have a list of projects that make economic sense, even at US$40/bbl.
    While the majority of the low cost opportunities are found in the prolific North American tight oil plays, other low cost destinations are emerging. Slimmed-down offshore designs are making some seaward projects competitive in the forty dollar range. Likewise, executives report that some onshore international developments can compete too.
  4. “Permania” takes hold. The recent buying frenzy in the nearby Permian basin was a frequent topic of discussion. Are the land prices on recent deals too high? How many horizontal “benches” of resource does the play have? How much infrastructure will be required?
    Today, the play produces just over 2 million bbls/d of oil and almost 8 Bcf/d of gas. Some at CERAWeek predicted that oil output could eventually reach 4 or 5 million bbls/d. Pioneer executive chairman Scott Sheffield was more optimistic, forecasting that Permian oil production would reach 8 or 10 bbls/d with 20 Bcf/d of associated gas by 2027.
  5. Peak oil demand is not on the horizon. Despite growing electric car sales, oil executives are not predicting peak oil demand anytime soon. Considering the limited alternatives to petroleum for trucking, heavy-duty hauling, shipping, aviation, petrochemical and other uses, it was argued that demand will keep pushing upward.
    International Energy Agency executive director Fatih Birol stated that, “If every second car sold was an electric car… we will still see global oil demand increasing.”
  6. Technology upside. While innovations in hydraulic fracturing and horizontal drilling were a frequent discussion topic, the future potential for using big data and automation stole the show.
    Today, only a fraction of the many terabytes of data collected on wells and fields is used for real-time decision making. If all of the data could be integrated and made available to humans and supercomputers alike, operations would become more efficient.
    Similarly, oilfield automation is in its infancy. By applying technology used in other industries a step change in oilpatch efficiency is possible. Anadarko’s CEO, Al Walker, said it best: “We need to be more like Silicon Valley.”
  7. White House predictions. Shortly after Exxon announced plans to spend US$20 billion in the US Gulf Coast over the next ten years, President Trump tweeted his support.
    Speakers predicted that the pro-business and pro-industry White House could simplify and streamline regulatory approvals. However, the ultimate impact was debated; state-level requirements and legal challenges could still delay project timelines.
    As for changes to trade deals and border adjustment taxes, numerous concerns were raised. Worries included the possibility of negative impacts for global oil and gas producers and the potential for barriers in selling US gas to Mexico.
  8. Canadian representation. Canada had the opportunity to champion the country’s oil and gas industry and investment strengths on the world stage. Premier Rachel Notley spoke on Alberta’s climate plan; federal natural resources minister Jim Carr highlighted the importance of Canada growing its access to international markets and Prime Minister Justin Trudeau received an award for global energy and environmental leadership at the conference.
    In his keynote address, Trudeau described the positive attributes of Canadian oil and gas, including energy security and reliability. Trudeau stated, “No country would find 173 billion barrels of oil in the ground and just leave them there.”

After a tough three years, the conference speakers confirmed that the industry is on the mend.

While there is optimism, even excitement, about the cost cutting innovation that has made some projects economic at lower oil prices, the industry is still fiscally cautious.

This fiscal conservatism will limit how many low cost projects can be sanctioned, and ultimately it will constrain how much US and other non-OPEC production can grow.

 

 

Canada’s oilpatch should not fret about the Permian Basin

Canada’s oilpatch should not fret about the Permian Basin: Yager

By David Yager

March 8, 2017, 2:24 p.m.

http://www.jwnenergy.com/article/2017/3/canadas-oilpatch-should-not-fret-about-permian-basin-yager/

 

oil patch

A Financial Post headline on February 17 declared “The Permian Basin: An existential threat to Canadian oil as the war on cost heats up.”

OMG! For oilfield services, you finally hire a few people and sneak through a price increase and the bank no longer hates you, but then you pick up the news and learn Canada’s recovery will be muted by an ancient oilfield in western Texas. Does the bad news ever end?

The flow of globally irrelevant data from the U.S. is relentless. The Baker Hughes active oil rig count in mid-February was not quite 600 and still only 37 per cent of the October 2014 peak, but rig productivity has skyrocketed, according to multiple sources. The aforementioned article noted crude output from the Permian was expected to rise by 400,000 bbls/d to 2.5 million bbls/d this year and perhaps rise by one million bbls/d by the end of 2018. Look out world.

Despite rising land and service costs, Permian geology is certainly favourable, and many operators can make money at US$40. The implication is this will pressure Canada in terms of attracting capital because so many operators are redeploying finite reserve replacement dollars from long-term projects, like the oilsands, to quicker returns, like the Permian. Numerous global operators like ExxonMobil, Royal Dutch Shell, Chevron and ConocoPhillips were looking at spending more in western Texas and less elsewhere.

But the fact that the Permian Basin might produce one million bbls/d more in 21 months is almost meaningless in the great scheme of global oil markets. The U.S. Energy Information Administration (EIA) estimated Feb. 7, 2017, that 2018 world oil demand will be 99.55 million bbls/d, putting the Permian at three per cent of global supply. How can the tail of a basin that dates back to the 1920s wag the world’s oil dog? It can’t, and it would sure be nice to stop reading about it.

If the EIA figures are remotely correct, oil demand in 2017-18 will rise by an average of 1.5 million bbls/d this year and next. Decline rates on existing production vary greatly by reservoir, but last year, IHS Markit, one of America’s most credible independent oil research outfits, released a report indicating global decline averages of 4.5 per cent per year. This was based on a study of 811 international oilfields accounting for two-thirds of world production. Offshore decline rates were higher than on land, but technology and advanced recovery methods were slowing the decline in most areas. While the decline rates in light, tight or shale oil wells are improving as recovery understanding grows, the long-term decline rate of these reservoirs is certainly greater than the IHS average.

So to keep up with global consumption and production patterns and using EIA data for 2017-18, the world is going to have to unlock 5.8 million bbls/d of new and incremental production in 2017 and an additional 5.9 million bbls/d in 2018. Exactly how the Permian Basin, 600 rigs (not all in western Texas) and enormously improved drilling productivity are going to move the needle on this figure is unknown. And it shall stay that way because it is never going to happen.

This is not to say the Permian Basin is not a wonderful collection of hydrocarbon-bearing rocks because it is. Since production began in 1921, this 75,000-square-mile, multi-zone mammoth has yielded 29 billion barrels of oil and 75 tcf of gas. The Railroad Commission of Texas website reports it could do that again. A new producing horizon called Wolfcamp is estimated to hold 20 billion recoverable barrels alone. Lots of Canadian operators and service companies are active in this region. Nothing wrong with that.

But to have the media continually focus on the Permian and the U.S. rig count as a problem and not an opportunity is simply wrong. The National Energy Board reports Canadian crude output increased by almost 100,000 bbls/d in 2016 despite the worst drilling year in recent history. Why is that not a problem? The Canadian Association of Petroleum Producers’ 2016 Canadian oil production forecast sees Canadian output increasing by 700,000 bbls/d from 2015 to 2020. Why is the news not worried about this?

Oilfield services can’t have it both ways. The working oilpatch can’t cheerfully go back to work replacing reserves as they decline, while at the same time, having these efforts declared as a threat to its own future. Finding more oil is not a problem. It is essential. Indeed, report the news. But please dig a bit deeper and tell the whole story

 

 

8 future technologies for carbon capture

8 future technologies for carbon capture

March 8, 2017, 6:49 a.m.

http://www.jwnenergy.com/article/2017/3/8-future-technologies-carbon-capture/

carbon capture

Osamu Terasaki (left) and his team at the University of Stockholm are creating crystals designed to capture carbon in the presence of water. Image: University of Stockholm

 

Deployment of carbon capture and storage (CSS) technology is “not optional” if the world hopes to meet the targets set out in the Paris climate agreement, the International Energy Agency said recently.

“IEA scenario analysis has consistently highlighted that CCS will be important in limiting future temperature increases to two degrees Celsius, and we anticipate that this role for CCS will become increasingly significant if we are to move towards well below two degrees Celsius,” IEA executive director Fatih Birol wrote in the foreword to 20 Years of Carbon Capture and Storage: Accelerating Future Deployment.

Canada has three large-scale CCS projects in commercial operation, including SaskPower’s CCS facility at the Boundary Dam Power Station near Estevan, Sask., the Weyburn-Midale enhanced oil recovery projects operated by Cenovus Energy and Apache Canada, and the Shell Quest project at the Scotford oilsands upgrader near Edmonton.

While CCS operators in Canada and globally work to improve existing technologies, in laboratories around the world, scientists are working on the next wave of technologies. Here is a look at several of them.

  1. Metal-organic frameworks

In recent years, a class of highly absorbent, nanoporous materials called metal-organic frameworks (MOFs) have emerged as a promising material for carbon capture in power plants.

“People are really excited about these materials because we can make a huge variety and really tune them,” says Northwestern University’s Randall Snurr. “But there’s a flip side to that. If you have an application in mind, there are thousands of existing MOFs and millions of potential MOFs you could make. How do you find the best one for a given application?”

Snurr and his group have discovered a way to rapidly identify top candidates for carbon capture—using just one per cent of the computational effort that was previously required. By applying a genetic algorithm, they rapidly searched through a database of 55,000 MOFs.

One of the identified top candidates, a variant of NOTT-101, has a higher capacity for CO2 than any MOF reported in scientific literature for the relevant conditions.

“The percentage of carbon dioxide that the MOF can absorb depends on the process,” Snurr says. “The [United States] Department of Energy target is to remove 90 per cent of carbon dioxide from a power plant; it’s likely that a process using this material could meet that target.”

With their nanoscopic pores and incredibly high surface areas, MOFs are excellent materials for gas storage. MOFs’ vast internal surface areas allow them to hold remarkably high volumes of gas. The volume of some MOF crystals might be the size of a grain of salt, for example, but the internal surface area, if unfolded, could cover an entire football field.

Snurr’s previous work has explored how to use MOFs to capture carbon from existing power plants during the post-combustion process. About 10–15 per cent of power plant exhaust is CO2; the rest is mainly nitrogen and water vapor. Snurr and his team have designed a MOF that can sort these gases to capture CO2 before it enters the atmosphere. Chemically processing the fuel before it enters the power plant can turn it into CO2 and hydrogen. After the MOF captures the CO2, the hydrogen is burned, and the only byproduct is water. This extra chemical processing step would need to be built into new power plants as a pre-combustion process.

“In places like China, where they are still building a lot of power plants,” Snurr says, “this would make a lot of sense.”

  1. Nanosponges

Cornell University materials scientists have invented low-toxicity, highly effective carbon-trapping “sponges” that could improve carbon capture economics.

A research team led by Emmanuel Giannelis has invented a powder that performs as well as or better than industry benchmarks for carbon capture.

The most common carbon capture method today is called amine scrubbing, in which post-combustion, CO2-containing flue gas passes through liquid vats of amino compounds, or amines, which absorb most of the CO2. The carbon-rich gas is then pumped away—sequestered—or reused. The amine solution is extremely corrosive and requires capital-intensive containment.

The researchers have been working on a better, safer carbon-capture method since about 2008, and they have gone through several iterations. Their latest consists of a silica scaffold, the sorbent support, with nanoscale pores for maximum surface area. They dip the scaffold into liquid amine, which soaks into the support like a sponge and partially hardens. The finished product is a stable, dry white powder that captures CO2 even in the presence of moisture.

Solid amine sorbents are used in carbon capture, Giannelis says, but the supports are usually only physically impregnated with the amines. Over time, some of the amine is lost, decreasing effectiveness and increasing cost.

The researchers instead grew their amine onto the sorbent surface, which causes the amine to chemically bond to the sorbents, meaning very little amine loss over time.

  1. Hybrid membranes

A new, highly permeable carbon capture membrane developed by scientists at the Lawrence Berkeley National Laboratory (Berkeley Lab) could lead to more efficient ways of separating CO2 from power plant exhaust.

The researchers focused on a hybrid membrane that is part polymer and part MOF.

In a first, the scientists engineered the membrane so that CO2 molecules can travel through it via two distinct channels. Molecules can travel through the polymer component of the membrane, like they do in conventional gas-separation membranes, or they can flow through “CO2 highways” created by adjacent MOFs.

Initial tests show this two-route approach makes the hybrid membrane eight times more CO2-permeable than membranes composed only of the polymer. Boosting CO2 permeability is a big goal in efforts to develop carbon capture materials that are energy efficient and cost competitive.

“In our membrane, some CO2 molecules get an express ride through the highways formed by metal-organic frameworks, while others take the polymer pathway. This new approach will enable the design of higher performing gas separation membranes,” says Norman Su, a graduate student in the chemical and biomolecular engineering department at the University of California, Berkeley and a user at the Molecular Foundry.

Berkeley Lab scientists have developed a hybrid membrane where MOFs account for 50 per cent of its weight, which is about 20 per cent more than other hybrid membranes. Previously, the mechanical stability of a hybrid membrane limited the amount of MOFs that could be packed in it.

“But we got our membrane to 50 weight per cent without compromising its structural integrity,” says Su.

And 50 weight per cent appears to be the magic number. At that threshold, there are so many MOFs in the membrane that they form a continuous network of highways through the membrane. When that happens, the hybrid membrane switches from having a single channel to transport CO2, in which the molecules must go through the polymer, to two channels, in which the molecules can either move through the polymer or through the MOFs.

“This is the first hybrid polymer-MOF membrane to have these dual transport pathways, and it could be a big step toward more competitive carbon capture processes,” says Su.

  1. Crystals

Swedish scientists have created crystals that capture CO2 much more efficiently than previously known materials, even in the presence of water.

One way to mitigate climate change could be to capture CO2 from the air. So far, this has been difficult since the presence of water prevents the adsorption of CO2. Complete dehydration is a costly process. Scientists have now created a stable and recyclable material where the micro-pores within the crystal have different adsorption sites for CO2 and water.

“As far as I know, this is the first material that captures CO2 in an efficient way in the presence of humidity. In other cases, there is competition between water and CO2, and water usually wins. This material adsorbs both, but the CO2 uptake is enormous,” says Osamu Terasaki, a professor in the department of materials and environmental chemistry at Stockholm University.

The new material is called SGU-29, named after Sogang University in South Korea, and is the result of international cooperation. It is a copper silicate crystal. The material could be used for capturing CO2 from the atmosphere and especially to clean emissions.

“CO2 is always produced with moisture, and now we can capture CO2 from humid gases. Combined with other systems that are being developed, the waste carbon can be used for new valuable compounds. People are working very hard, and I think we will be able to do this within five years. The most difficult part is to capture CO2, and we have a solution for that now,” says Terasaki.

  1. Turning carbon to rock

An international team of scientists report they may have found a potentially permanent way to remove CO2 emissions from the atmosphere—turn it into rock.

The study, published in Science, has shown for the first time that CO2 can be permanently and rapidly locked away from the atmosphere by injecting it into volcanic bedrock. The CO2 reacts with the surrounding rock, forming environmentally benign minerals.

Until now, it was thought that this process would take several hundreds or thousands of years and is therefore not a practical option. But the current study—led by Columbia University, the University of Iceland, the University of Toulouse and Reykjavik Energy—has demonstrated that it can take as little as two years.

Juerg Matter, the lead author and associate professor in geoengineering at the University of Southampton, says: “Our results show that between 95 and 98 per cent of the injected CO2 was mineralized over the period of less than two years, which is amazingly fast.”

The gas was injected into a deep well at the study site in Iceland. As a volcanic island, Iceland is made up of 90 per cent basalt, a rock rich in elements required for carbon mineralization, such as calcium, magnesium and iron. The CO2 is dissolved in water and carried down the well. On contact with the target storage rocks at 400–800 metres under the ground, the solution quickly reacts with the surrounding basaltic rock, forming carbonate minerals.

“Carbonate minerals do not leak out of the ground, thus our newly developed method results in permanent and environmentally friendly storage of CO2 emissions,” says Matter, who is also a member of the University’s Southampton Marine and Maritime Institute and an adjunct senior research scientist at Lamont-Doherty Earth Observatory at Columbia. “On the other hand, basalt is one of the most common rock type on Earth, potentially providing one of the largest CO2 storage capacity.

“The overall scale of our study was relatively small. So, the obvious next step for CarbFix is to upscale CO2 storage in basalt. This is currently happening at Reykjavik Energy’s Hellisheiđi geothermal power plant, where up to 5,000 tonnes of CO2 per year are captured and stored in a basaltic reservoir.”

The investigation is part of the CarbFix project, a European Commission– and Department of Energy–funded program to develop ways to store anthropogenic CO2 in basaltic rocks through field, laboratory and modelling studies.

  1. Turning carbon into fuel

They’re making fuel from thin air at the University of Southern California’s Loker Hydrocarbon Research Institute.

For the first time, researchers there have directly converted CO2 from the air into methanol at relatively low temperatures.

The work—led by G.K. Surya Prakash and George Olah from the chemistry department at USC Dornsife—is part of a broader effort to stabilize the amount of CO2 in the atmosphere by using renewable energy to transform the greenhouse gas into its combustible cousin, attacking global warming from two angles simultaneously. Methanol is a clean-burning fuel for internal combustion engines, a fuel for fuel cells and a raw material used to produce many petrochemical products.

“We need to learn to manage carbon. That is the future,” says Prakash, the director of the Loker Hydrocarbon Research Institute.

The researchers bubbled air through an aqueous solution of pentaethylenehexamine, adding a catalyst to encourage hydrogen to latch onto the CO2 under pressure. They then heated the solution, converting 79 per cent of the CO2 into methanol. Though mixed with water, the resulting methanol can be easily distilled, Prakash says.

The new process was published in the Journal of the American Chemical Society. Prakash and Olah hope to refine the process to the point that it could be scaled up for industrial use, though that may be five to 10 years away.

“Of course it won’t compete with oil today, at around $30/bbl,” Prakash says, “but right now we burn fossilized sunshine. We will run out of oil and gas, but the sun will be there for another five billion years. So we need to be better at taking advantage of it as a resource.”

Despite its outsized impact on the environment, the actual concentration of CO2 in the atmosphere is relatively small—roughly 400 parts per million or 0.04 per cent of the total volume, according to the National Oceanographic and Atmospheric Administration. (For a comparison, there’s more than 23 times as much argon in the atmosphere, which still makes up less than one per cent of the total volume.)

Previous efforts have required a slower multistage process with the use of high temperatures and high concentrations of CO2, meaning that renewable energy sources would not be able to efficiently power the process, as Olah and Prakash hope.

The new system operates at around 125–165 degrees Celsius, minimizing the decomposition of the catalyst, which occurs at 155 degrees Celsius. It also uses a homogeneous catalyst, making it a quicker “one-pot” process. In a lab, the researchers demonstrated that they were able to run the process five times with only minimal loss of the effectiveness of the catalyst.

  1. Turning carbon into fibres

Finding a technology to shift CO2 from a climate change problem to a valuable commodity has long been a dream of many scientists and government officials. Now, a team of chemists says they have developed a technology to economically convert atmospheric CO2 directly into highly valued carbon nanofibres for industrial and consumer products.

“We have found a way to use atmospheric CO2 to produce high-yield carbon nanofibres,” says Stuart Licht, who leads a research team at George Washington University. “Such nanofibres are used to make strong carbon composites, such as those used in the Boeing 787 Dreamliner, as well as in high-end sports equipment, wind turbine blades and a host of other products.”

Previously, the researchers had made fertilizer and cement without emitting CO2, which they reported. Now, the team says their research could shift CO2 from a global-warming problem to a feedstock for the manufacturing of in-demand carbon nanofibres.

Licht calls his approach “diamonds from the sky.” That refers to carbon being the material that diamonds are made of and also hints at the high value of the products, such as the carbon nanofibres, that can be made from atmospheric carbon and oxygen.

Because of its efficiency, this low-energy process can be run using only a few volts of electricity, sunlight and a whole lot of CO2. At its root, the system uses electrolytic syntheses to make the nanofibres. CO2 is broken down in a high-temperature electrolytic bath of molten carbonates at 750 degrees Celsius. Atmospheric air is added to an electrolytic cell. Once there, the CO2 dissolves when subjected to the heat and direct current through electrodes of nickel and steel. The carbon nanofibres build up on the steel electrode, where they can be removed, Licht says.

To power the syntheses, heat and electricity are produced through an extremely efficient hybrid solar-energy system. The system focuses the sun’s rays on a photovoltaic solar cell to generate electricity and on a second system to generate heat and thermal energy, which raises the temperature of the electrolytic cell.

Licht estimates electrical energy costs of this “solar thermal electrochemical process” to be around $1,000/ton of carbon nanofibre product, which means the cost of running the system is hundreds of times less than the value of product output.

“We calculate that, with a physical area less than 10 per cent the size of the Sahara Desert, our process could remove enough CO2 to decrease atmospheric levels to those of the pre-industrial revolution within 10 years,” he says.

At this time, the system is experimental, and Licht’s biggest challenge will be to ramp up the process and gain experience to make consistently sized nanofibres. “We are scaling up quickly,” he adds, “and soon should be in range of making tens of grams of nanofibres an hour.”

Licht explains that one advance the group has recently achieved is the ability to synthesize carbon fibres using even less energy than when the process was initially developed. “Carbon nanofibre growth can occur at less than one volt at 750 degrees Celsius, which for example, is much less than the three to five volts used in the 1,000-degree-Celsius industrial formation of aluminum,” he says.

 

 

 

Get ready for a six-fold jump in Canadian crude-by-rail shipments this year: IEA

Get ready for a six-fold jump in Canadian crude-by-rail shipments this year: IEA

By Deborah Jaremko

March 7, 2017, 7:49 a.m.

http://www.jwnenergy.com/article/2017/3/get-ready-six-fold-jump-canadian-crude-rail-shipments-year-iea/

 

oil by rail

Image: Joey Podlubny/JWN

More oil is going to find its way onto the rails in Canada this year as the country is left without enough pipeline capacity for continued production growth until at least 2019, the International Energy Agency (IEA) said on Monday.

By 2022 Canadian oil production is expected to grow by 820,000 bbls/d to 5.3 million bbls/d, the IEA said in its new five-year oil market outlook.

The net increase is driven entirely by oilsands growth despite new offshore volumes as conventional oil production declines.

“As Canadian oil output continues to grow, producers are looking ahead to an urgently needed expansion of the export network,” the IEA said.

“When pipeline capacity has not been available or domestic needs have fallen, rail shipments offer a vital relief valve. That is sure to be the case again. As no new pipeline capacity will be added before 2019, crude exports by rail could jump from 80,000 bbls/d in 2016 to 520,000 bbls/d in 2017 before falling back to 430,000 bbls/d in 2018.”

The IEA projects this will drop again to an average 105,000 bbls/d over 2019-22 as supply growth eases and as additional pipeline capacity comes online.

“According to the National Energy Board, total crude oil rail loading capacity in Western Canada is 1 million bbls/d, well above crude-by-rail needs in 2017 and 2018.”

The export bottleneck is expected to have a significant impact on prices, the IEA says, as the differential between Western Canadian Select and West Texas Intermediate typically reflects the cost to move crude from origin to destination as well as the difference in its quality.

When rail shipments rose between 2011 to 2014, the price differential between WTI/WCS widened to around US$20/bbl on average, reaching as much as US$39/bbl in December 2013. The discount then fell to US$13-14/bbl in 2015 and 2016 as oil prices fell, the IEA notes, which was barely enough to cover rail costs.

“With rail shipments set to rise, producers in Alberta will have to offer a discount to WTI and other crudes such as Mexican Maya, which can be shipped to the US Gulf Coast for a few dollars a barrel.”

The IEA expects the differential to drop after 2020, provided that new pipeline infrastructure is built, but “the reliance on US markets and associated transport costs may maintain the pressure on Canadian crude prices. As such, a diversification of export outlets and spare transport capacity is desirable. Otherwise, Canada might face restricted access to markets where the highest growth in crude oil demand is concentrated – namely Asia.”

 

 

 

Energy firms urged to better engage public

Industry enjoying ‘upstream confidence’, but pipeline constraints could choke opportunities, says Enbridge CEO

JESSE SNYDER, FINANCIAL POST  03.06.2017

Enbridge CEO

Al Monaco, president and chief executive officer of Enbridge Inc., speaks during the 2017 IHS CERAWeek conference in Houston, Texas, U.S., on Monday, March 6, 2017. CERAWeek gathers energy industry leaders, experts, government officials and policymakers, leaders from the technology, financial, and industrial communities toprovide new insights and critically-important dialogue on energy markets.

 

HOUSTON, TX. — Pipeline companies need to get better at communicating with local communities, the chief executive of Canada’s largest midstream company said Monday, as major new infrastructure projects continue to be snarled in regulatory delays.

“Industry needs to up its game,” Enbridge Inc. CEO Al Monaco told a large gathering of oil and gas professionals attending the IHS CERA week in Houston Monday.

“We’re not whining about what’s happening, but we do need to get better when it comes to developing and executing projects.”

Monaco’s comments come after a number of major pipeline projects in Canada were recently approved, including Kinder Morgan Inc.’s Trans Mountain expansion and Enbridge’s Line 3 replacement. TransCanada Corp.’s Keystone XL proposal to the U.S. Gulf Coast was also revived recently after President Donald Trump signed an executive order urging the project forward.

However, public discontent with pipeline expansions continues to plague pipeline expansion plans, with many environmental groups and local residents promising to  block the construction of those proposals.

Monaco said that pipeline companies need to improve their consultations with stakeholders of all kinds, including local communities, to better communicate their ideas and hear the criticisms of those who are wary of fossil fuel development.

“It’s this ‘how’ to do things that’s critical moving from, let’s call it consultation, to actually listening and carefully responding to peoples’ concerns,” he said.

There was a tinge of irony to the comments, which were addressed toward an exclusive group of oil and gas industry members. The industry has long been criticized for its insularity and lackluster communication strategy with the public. In recent years, however, pipeline companies have spent much time and capital on public relations efforts.

The Northern Gateway Pipeline, a proposal that would have transported heavy oil from Alberta to the B.C. West Coast, was rejected in late 2016 by Canadian Prime Minister Justin Trudeau.

First Nations along the proposed route of the project said early-stage consultations weren’t adequate to account for their concerns.

Monaco’s comments come amid a general feeling of optimism among the industry members gathered, despite a decidedly miserable and rainy day outside. It is a stark contrast from the gloomy atmosphere of the last few years of the annual event, which is one of the highest-profile energy events in the world.

The Trans-Alaska Pipeline System, which we call TAPS, that crosses three mountain ranges, 34 rivers, and hundreds of small streams, I think there’s a lot of positive energy here such a despairing message,” said Daniel Sullivan, a Republican Senator representing Alaska.

Much of that optimism is tied to the resilience of light, tight oil producers in the U.S., who have proven among the lowest cost operators in the market.

However, opposition to infrastructure expansion remains a concern among U.S.-focused producers, who are eager to ease an ongoing pipeline bottleneck.

“I’m glad to see the focus we’re putting on it,” said Exxon Mobil Corp. CEO Darren Woods.

The company has refocused much of its spending on the Permian Basin in northwest Texas and southeast New Mexico, located just a short distance from where industry members are gathered in Houston.

Monaco said the “dynamics of continental energy transportation are changing” as new supplies of oil and gas are being opened up in Canada and the U.S., mostly due to the use of a combination of horizontal drilling and multi-stage fracking processes over the past 15-odd years.

“There is a building momentum in our industry,” Monaco said.

As a result of lower oil prices, companies are also beginning to trim back operation costs to remain competitive with overseas producers, he said.

“It’s really about upstream confidence.”

However, Monaco warned that a failure to build pipeline projects would handicap producers in North America, which have the opportunity to be among the most competitive oil producers.

“We’re going to miss global export opportunities.”

 

 

 

$20-billion gulf-coast expansion good news for Saskatchewan oil

And a lot of the oil processed by these expansions will come from Saskatchewan and Alberta!

Trump cheers Exxon plan to spend $20B on Gulf Coast projects

DAVID KOENIG, THE ASSOCIATED PRESS  03.06.2017

 Exxon CEO

Darren Woods, Exxon Mobil CEO, speaks during CERAWeek at the Hilton Americas,Monday, March 6, 2017, in Houston. (Melissa Phillip/Houston Chronicle via AP)

 

HOUSTON – President Donald Trump and Exxon Mobil Corp. exchanged praise for each other on Monday as the company announced plans to create thousands of jobs by spending $20 billion over 10 years on plants along the Gulf Coast.

Exxon’s plan started long before Trump entered the White House, however. It includes investments that began in 2013.

Exxon said Monday the work would create 12,000 permanent jobs — the energy giant currently has about 71,000 employees — and 35,000 construction jobs.

Exxon announced its plan in a news release in which CEO Darren Woods was quoted as saying that such big investments “require a pro-growth approach and a stable regulatory environment and we appreciate the President’s commitment to both.”

A few minutes later, the White House issued its own release about Trump congratulating Exxon. One paragraph in the White House release is nearly identical to a passage in Exxon’s.

The president followed up on Twitter, saying that “Buy American & hire American are the principals at the core of my agenda,” although he apparently meant that those are among his principles.

In his third tweet on Exxon, Trump wrote, “45,000 construction & manufacturing jobs in the U.S. Gulf Coast region. $20 billion investment. We are already winning again, America!”

In December, Trump plucked Exxon’s then-CEO, Rex Tillerson, to be his secretary of state. Tillerson and Trump met Monday shortly before the Exxon and White House press releases.

Woods, the new chairman and CEO, said Monday that Exxon would expand at several current plants and build a new one to create petroleum products for export.

Woods said the investment plan responds to the rising supply of natural gas. There has been a boom in production created by techniques such as fracking, or hydraulic fracturing, in shale formations like the Permian Basin of Texas and New Mexico.

Exxon recently agreed to buy rights to about 250,000 more acres, doubling its presence in the Permian at a cost of up to $6.6 billion — a huge bet on the hottest oil and gas field in the country.

Woods said hydraulic fracturing has “opened up a whole new energy future for the United States … (that) is turning the U.S. from energy importer to energy exporter.”

Exxon announced the spending plan at a major energy-industry conference in Houston that draws executives and oil ministers from around the world.

The company said it plans 10 expansion projects at refineries and chemical and liquefied natural gas plants around Beaumont and Baytown, Texas, and Baton Rouge, Louisiana. It also wants to build a new chemicals plant at a location yet to be determined along the Gulf.

The sum of $20 billion would be roughly equal to Exxon’s total capital spending last year. The company announced last week that it plans to increase overall investments to an average of $25 billion a year from 2018 to 2020.

Shares of the Irving, Texas-based company rose 37 cents to close at $82.83. They have lost about 8 per cent so far this year.

 

 

 

Five oilfield services companies discuss the increasing labour challenge as activity picks up

Five oilfield services companies discuss the increasing labour challenge as activity picks up

By Deborah Jaremko

March 3, 2017, 1:56 p.m.

http://www.jwnenergy.com/article/2017/3/five-oilfield-services-companies-discuss-their-labour-challenges-activity-picks/

 

A familiar problem is facing Canada’s oilfield service providers as they emerge from one of the worst downturns in decades—there aren’t enough workers to fill increasing demand.

It’s the middle of fourth quarter earnings season, when companies announce their operating and financial results from last year and their outlook for the future.

Stabilized commodity prices have encouraged producers to step up drilling activity, and the growing staffing issue is a common thread in response from drilling service providers.

Here is a selection of commentary from five key companies in recent Daily Oil Bulletin detailed coverage.

  1. Canyon Services Group

Canyon Services Group says that right now demand “far outweighs” its ability to supply crews as commodity prices improve and producers are putting them back to work.

However, the company expects to have both enough workers and equipment by this summer or fall.

Canyon Services has been operating at full staffing capacity since the middle of November and it expects to be in this position for the rest of 2017, said chief executive officer Brad Fedora.

At current levels all service companies would put their parked equipment back to work if they could staff it, but they can’t, he said. During spring breakup Canyon will try to add at least 100 people to its employee roster because it is “basically sold out” for the rest of 2017.

The promise of higher pay will lure many who were laid off back to the oilpatch, Fedora said.

“Now that we have had six months of positive momentum in the pressure pumping business and once we get breakup behind us we think those people will return to the oilfield,” said Fedora. “Obviously the pay is better than [in] most industries but a lot of the people were quite spooked given what had happened in the prior two years with respect to spring layoffs.”

  1. Cathedral Energy Services

Cathedral Energy Services says the “dramatic” improvement in its business prospects that began in the fourth quarter of 2016 has led to a challenge—finding enough skilled labour to meet the increased demand.

The company says its active job count has doubled since September 2016 and more than tripled since the lows in early 2016.

“This has presented a completely new set of challenges as we have had to aggressively ramp up our business. Compared to the last two years, these are good challenges to have,” the company said in its fourth quarter and year-end 2016 earnings release.

“The big issue for Cathedral and our industry in this improved environment has been staffing up to meet demand. Attracting workers back to the industry has been a challenge particularly in Canada due to the industry seasonality factors.”

  1. Calfrac

Labour could become an issue as pressure-pumpers gear up for a recovery, Calfrac Well Services said in reporting its fourth-quarter 2016 results.

“The labour market is and will continue to be tight, and the company believes this will be a significant constraint in bringing additional capacity back into service,” the company said.

Last year was among the most challenging ever for North American pressure-pumpers, management said, noting the U.S. land rig count fell to 380 rigs while the Canadian count slipped as low as 34 rigs in 2016.

Since the start of 2017, Calfrac said activity has been strong and expects full utilization of its active fleet in Canada through to spring breakup.

In the U.S., the company said it seeing stronger demand in the Bakken and Marcellus.

  1. Essential Energy Services

Essential Energy Services says it is having trouble finding enough people to crew its equipment even though its headcount was increased 18 per cent between September and December last year (to 348 at the end of 2016 from 295, excluding its service rig division, sold in December), and 35 per cent since first-quarter 2016.

Hydraulic fracturers and large drillers are setting the pace for service price increases, but a labour shortage may be a limiting factor for activity, Essential says.

The company is continuing to hire during the first quarter, primarily in its coil-well service division, and expects that to continue through the year, attracting candidates through advertising, referral bonuses, word-of-mouth and dedicating additional resources to recruiting, according to Karen Perasalo, vice-president of investor relations and corporate secretary.

“We are finding there are not enough ready-to-work people so we are training and developing new-to-industry or new-to-Essential people, which takes additional training time.”

  1. Trinidad Drilling

With increased activity, Trinidad Drilling has had to beef up its labour pool, a situation that CEO Lyle Whitmarsh says has gone smoothly but recognizes it may get harder.

“To date we’ve been able to successfully crew reactivated rigs. During the downturn we kept our most experienced crews and redistributed them throughout our fleet. As activity levels have increased, we have been able to move those crews back to their previous roles,” he said.

“In addition, since our low in the second quarter of 2016 we have added approximately 850 employees. The majority of them were previous Trinidad employees.”

As activity continues to increase, Whitmarsh acknowledged that crewing rigs will be more challenging. That said, he’s confident the company will be able to meet that challenge.

“Our management team has a strong record of successfully crewing rigs during the most challenging conditions, including following the last downturn,” he said.

“We have carefully laid out plans and processes to find skilled crews and we expect that our past experience and thorough planning will position Trinidad well to crew rigs.”

 

 

Keystone XL can be made from non-U.S. steel: White House

Fri Mar 3, 2017 | 3:25pm EST

REUTERS

Keystone XL can be made from non-U.S. steel: White House

pipe

A depot used to store pipes for Transcanada Corp’s planned Keystone XL oil pipeline is seen in Gascoyne, North Dakota, January 25, 2017.REUTERS/Terray Sylvester

The Keystone XL oil pipeline does not need to be made from U.S. steel, despite an executive order by President Donald Trump days after he took office requiring domestic steel in new pipelines, the White House said on Friday.

“It’s specific to new pipelines or those that are being repaired,” White House spokeswoman Sarah Sanders told reporters on Air Force One, when asked about a report by Politico that Keystone would not need to use U.S. steel, despite Trump’s executive order issued on Jan. 24.

“Since this one is already currently under construction, the steel is already literally sitting there, it’s hard to go back. Everything moving forward would fall under that executive order,” Sanders said. The southern leg of the Keystone project is completed and started pumping oil in 2013. Some pipe segments that could be used for Keystone XL, which would bring oil from Alberta, Canada to Nebraska, have already been built.

Former Democratic president Barack Obama rejected TranCanada Corp’s (TRP.TO

) multi-billion dollar Keystone XL pipeline, saying it would not benefit U.S. drivers and would contribute emissions linked to global warming.

Trump’s order expedited the path forward for TransCanada to reapply to build the line. Economists told Reuters days after Trump issued the order on U.S. steel requirements that it had many loopholes, would not be easily enforceable, and could violate international trade law.

Even if there were no loopholes, U.S. steelmakers would receive negligible benefit from Keystone XL, because they have limited ability to meet the stringent materials requirements for the project.

The office of Canadian Prime Minister Justin Trudeau on Friday said it welcomes the allowance of non-U.S. steel, calling it a “recognition that the integrated Canadian and U.S. steel industries are mutually beneficial.”

TransCanada said it was encouraged by the White House statement on non-U.S. steel and that its presidential permit application on Keystone was making its way through the approval process.

Canadian Public Safety Minister Ralph Goodale said on Twitter that allowing non-U.S. steel was “important for companies like Evraz Steel,” a local subsidiary of Russia’s Evraz PLC, which had signed on to provide 24 percent of the steel before Keystone XL’s rejection by Obama.

(Reporting by Melissa Fares on Air Force One, Ethan Lou in Calgary and Timothy Gardner in Washington; Editing by Chizu Nomiyama)

 

 

 

TransCanada’s Keystone pipeline to be exempted from ‘Buy American’ provisions

TransCanada’s Keystone pipeline to be exempted from ‘Buy American’ provisions

JEFFREY JONES

Calgary — The Globe and Mail

Published Friday, Mar. 03, 2017 1:56PM EST

Last updated Friday, Mar. 03, 2017 2:00PM EST

 

 

TransCanada Corp.’s Keystone XL pipeline is being exempted from so-called “Buy American” provisions that would force it to use pipe made solely from U.S. steel, according to media reports.

 

Such an exemption by the administration of President Donald Trump would remove a major impediment to TransCanada proceeding with the $8-billion (U.S.) project that had been rejected by the Obama administration in 2015. With an executive order in January, Mr. Trump set the wheels in motion for the application to be resurrected.

The President has called for a stipulation that U.S. steel be used in new, expanded or retrofitted pipelines “to the maximum extent possible.”

“The Keystone XL pipeline is currently in the process of being constructed, so it does not count as a new, retrofitted, repaired or expanded pipeline,” Politico quoted a White House spokeswoman as saying.

It was not clear what the White House official meant when she said the project is being constructed. The southern portion was split off from the initial blueprints and constructed as the Gulf Coast project. It began shipping oil in 2014. The remainder of the project has been in limbo since then. TransCanada resubmitted its application in late January.

TransCanada would not comment directly on the Buy American issue, or whether it has been told that it is exempt. However, spokesman Terry Cunha pointed out that half the pipe the company purchased in 2012 for Keystone XL was manufactured in the United States, and that 75 per cent originated in North America.

 

 

 

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