FluidFlow v3.42

Fixed a bug that occured when selecting “mm Water g” OR “m Water g” units.This was originally fixed in V3.39 but regressed in V3.41. New procedures in place to eliminate code regressions.

FluidFlow v3.41

General Release info:

Improved pipe heat loss calculation with the addition of new correlation for estimating outside film heat transfer coefficient. Bug fixes.


* Crane Tee Junction TP410 pre 2009 relationships. New recommendation is to use for existing/legacy calculations ONLY. Input editor text now reflects this.

The relationships are just too simplistic to realistically predict the pressure losses over all possible operating conditions and totally ignore any pressure recovery effects.

* All Heat Transfer Coefficients in pipe results were shown as W/m C where units shown are W/m2 C. Coefficient values now normalised to W/m2C by multiplying original value by the log mean radius.

This is more in line with most literature sources. Change was made not because answers or calculations are incorrect but because it is now easier compare values directly with common literature sources.

* Following a suggestion from some of our German customers, we incorporated a new improved method for estimating the outside coefficient in pipe heat loss/gain calculations.

The literature source for the improved method is the Springer publication “VDI Heat Atlas (VDI Wärmeatlas)”.

Previously FluidFlow used ASTM Standard C680. It is still possible to use the original ASTM Standard C680 relationship, selected from the Options -> Calculations Dialog -> Global Settings tab.

* Co2 gas density and specific heat definitions have been adjusted to provide more accurate results over a wider temperature and pressure range.


* Diffusers at choked conditions show the inlet results as outlet results.

* In networks containing centrifugal pumps and more than one fluids with viscosities of > 800 cP, sometimes Pump viscosity corrections were made when this should not be the case.

* Outside heat loss convection was overestimated in rare cases for gas flow along medium/long pipes.

* Improved convergence testing to prevent the solver converging too soon. For gas calculations this sometimes resulted in incorrect downstream temperatures.

* Reservoir No Flow – Bug in creation of accumulator for solver.

* Pump derating and speed changes were not working when both effects occurred together.

FluidFlow v3.40

General Release info:

Control Valves: Improved consistency of calculated valve position and valve coefficient over the complete operating range.

Polyethylene pipes, new pipe sizes added.

Petroleum fraction properties, NBP050 to NPB450 range added to fluids database.


  • Added back a directional definition for all flow control valves. This requires the user to specify the flow direction through the valve and is necessary to reduce interaction between flow control valves in large networks
  • Removed Text Import and Export menu options because format is now out of date and is not supported in the future.


  • Multiple flow controllers in a network could occasionally cause convergence BEFORE the network has actually converged. See changes above.
  • Liquid line with heat transfer in buried pipes, sometimes calculated out phase state as two-phase when phase state should be liquid.
  • Pipe scaling was not read in properly from old files (pre V3.30).

FluidFlow v3.39

General Release info:

Calculation procedures for viscosity correction method for centrifugal pumps has been updated to HI 2015 guidelines

Bug Fix:

Units m Water g and mm Water g went missing in V3.38. Now reinstated.

FluidFlow v3.38

Contains fixes for all reported bugs up to end of September 2016.

General Release info:
No new enhancements, bug fix maintenance release only

None in this release

* Fixed a rounding error (<2%) that occurred when converting to m Water and m Water gauge.
* Improved the chart visibility of slug region in two-phase flow pattern maps, previously part of the area was overwritten by elongated bubble regime.
* Fixed a bug in outlet velocity calculation when phase change occurs within a pipe.
* Fixed a bug that caused phase change within a pipe when Heat Loss Model = “Ignore Heat Loss/Gain”, without taking into account heat of vaporization.
* Fixed a bug that caused flow reversal at known flow nodes out of a network at very high specified flows i.e. many times greater than sonic flow.
* Fortis Only – Overcome the instability caused by the discontinuities in the Universal Gas Sizing Equation for control valves.
* Fixed a bug which shows gauge pressure results incorrectly if atmospheric pressure is changed.

Oil Rallies As Fears Over Brexit Subside

A picture shows section of the BP ETAP (...A picture shows section of the BP ETAP (Eastern Trough Area Project) oil platform in the North Sea, around 100 miles east of Aberdeen, Scotland on February 24, 2014. The British cabinet will meet in Scotland for only the third time in history to announce plans for the country's oil industry, which it warns will decline if Scots vote for independence. The fate of North Sea oil revenues will be a key issue ahead of the September 18 referendum to decide whether Scotland will end its 300-year-old union with England, and is expected to be the focus of Prime Minister David Cameron's cabinet meeting.  AFP PHOTO / POOL / ANDY BUCHANANAndy Buchanan/AFP/Getty Images

Oil rallied on June 20, lifted by a wave of investor confidence and a weaker dollar after polls showed a diminishing chance that Britain may vote to leave the European Union (EU) later this week.

August Brent crude futures were up 85 cents at $50.02 a barrel by 5:55 a.m. CT (10:55 GMT), set for a gain of 6% in two trading days. NYMEX crude for July delivery, which expires on June 21, was up 80 cents at $48.78 a barrel.

Campaigning for Britain’s vote on EU membership resumed on June 19 after a three-day hiatus prompted by the killing of a pro-EU lawmaker.

Three opinion polls ahead of the June 23 vote showed the ‘Remain’ camp recovering some momentum, although the overall picture remained one of an evenly split electorate.

Investment safe havens such as gold, the U.S. dollar , German bonds and the Swiss franc came under pressure, while oil looked set for its largest two-day rise in a month and the likes of copper and equities rallied.

“For oil as a risky asset, what we’ve seen are intraday gyrations that are coming from the spillover effects of ‘risk-on/risk-off’ moves that follow the poll numbers,” BNP Paribas global head of commodity strategy Harry Tchilinguirian said.

The pound climbed 1.6% to $1.4589, extending a recovery from June 16 more than two-month trough of $1.4013.

“With Brexit dominating the market headlines, it might be moves in the U.S. dollar that drive the oil market at least until we get that out of the way,” said Michael McCarthy, chief market strategist at CMC Markets in Sydney.

“It’s likely to be a nervous and skittish week’s trading.”

Oil prices continued to recover despite data showing U.S. energy firms adding oil rigs for a third week in a row, suggesting higher production to come.

Oil services firm Baker Hughes Inc. (NYSE: BHI) reported nine rig additions in the week to June 17.

Aside from Brexit concerns, the market is likely to be caught in a range as any gains would likely be limited by the return of more shale drillers in the United States, CMC’s McCarthy said.

“Capping market gains at the moment is the potential for those very agile U.S. producers to jump back into production should we see any further substantial rises,” he said.

Source: http://www.oilandgasinvestor.com/ 

Turkish firm secures $4.2bn Iran power plant deal


Unit International, a Turkish-owned but Brussels-based energy firm held by businessman Unal Aysal has been contracted to build seven power plants in Iran, with a total installed capacity of 6GW.

The contracts were signed in Tehran on 1 June, with Iran’s Thermal Power Plants Holding Company, which is acting on behalf of the country’s energy ministry.

Once completed, the plants are expected to increase Iran’s current energy output by as much as 10%.

According to Mohsen Tarztalab, MD of Thermal Plants, more than a thousand hours of negotiations took place, over a period of a year, before an agreement covering all the plants was reached.

Construction on the power stations is set to begin in the first quarter of 2017, with Unit International providing the capital for the build.

Once completed, the agreement will see Unit International operating the power stations for 20 years.

Mr Aysal said the deal constituted the largest investment made in Iran since UN sanctions were lifted and “one of the largest made in a single package in the world”.

Unit International had previously begun building gas power stations in Iran, including the 2.2GW Rudeshur project in Tehran, before work was interrupted by the 2006 UN sanctions.

source: http://www.constructionweekonline.com/


Experts: Gas Power’s Expansion Riddled with Roadblocks


Even though it may dominate forecasts, natural gas–fired generation faces a troubled expansion in the U.S., according to experts from a variety of stake-holding entities—including an industry group, a utility, a generator, and a pipeline company.

Challenges that have few solutions—from price volatility, to gas transport concerns, to rule uncertainty—may upend the nation’s dependence on natural gas, they cautioned.

Gas Price Volatility

The ultimate driver for the nation’s much-talked-about shift to natural gas generation has been low natural gas prices, as Lola Infante, director of generation fuels for industry group Edison Electric Institute, told attendees at the Gas Power 2016 conference in Houston, Texas, on June 8.

If standard heat rates were used to convert natural gas and coal prices to prices for electricity generation, this May marked the seventh consecutive month that natural gas prices at Henry Hub, averaging $15.87/MWh, were less than Appalachian coal prices, which remained relatively stable at $18.40/MWh. Meanwhile, record amounts of natural gas are being used for electricity generation. But looming over the power generation sector that is leaning on natural gas to fuel its future is price volatility, she warned. “If natural gas prices go up, the fuel switching will stop, and if gas prices continue to stay low, then it will continue to go really fast,” she said.

The nation’s build-out of natural gas is also being prompted by grid flexibility needs created by the integration of variable renewables, Infante said. In 2015, she noted, of the 14.5 GW of new capacity added in the U.S., 47% was wind, 35% natural gas, and 14% was solar.

She also noted that power plant retirements—not just coal retirements—were driving new gas plant additions (see POWER‘s June 2016 BIG PICTURE infographic for an analysis of retirements by fuel over the last decade). While environmental rules and economics have forced or will force mass retirements of coal plants, a large swathe of mostly natural gas steam turbine plants are also more than 65 years old—and many are due to retire.

The Midcontinent Independent System Operator (MISO) and PJM Interconnection areas have been hardest hit by coal retirements, yet the retirement trend is still “fluid,” she said, adding, “At any point, things could change, or they could move in a different direction.”

At the same time, a number of “transformation drivers” pose more uncertainties, including public policies (such as for climate change mitigation), financial incentives like tax credits, customer demand, such as for rooftop solar, and new technologies, models, and uses. For example, “[distributed generation] is the hottest topic in D.C. right now,” she said.

Energy storage, too, has come out of the “wishful thinking category” and into the real world, and its growth is projected to be exponential. Additionally, microgrids are multiplying, and utility-ownership models are in flux, she said.

Grave Market Concerns

From the utility perspective, too, the rapid shift to natural gas within an already morphing power landscape has been dizzying. The shale gas fracking revolution that changed the scene only got started in 2008, noted John Kosub, director of CPS Energy’s supply side analytics division. Just five years ago, the San Antonio, Texas–based municipal utility—the nation’s largest—used natural gas to fire 17% of its fleet. Today 43% of its markedly more diverse fleet is gas-fired.

But the transition hasn’t been all rosy, Kosub said, pointing to market concerns that are evolving within the Electric Reliability Council of Texas (ERCOT) region covering most of Texas. ERCOT, which is facing retirements of up to 4.7 GW of coal capacity owing to the Clean Power Plan and regional haze requirements, wants to add 6.2 GW of new gas-fired generation by summer 2018. Adapting to the changing landscape, it is also looking at ancillary services and a future distributed energy resources (DER) framework, he said.

Between 2010 and 2015, the reliability gatekeeper that was confronting a negative reserve margin just three years ago added 2 GW of natural gas, 1.6 GW of coal, 7.1 GW of new wind, and 740 MW of new solar capacity. But adding new capacity has had the effect of lowering market prices on average while “most generators are already challenged in this current market.” Kosub said.

ERCOT’s changing fuel mix. Compared to 2011, when natural gas fueled 40% of power plants on the grid overseen by the Electric Reliability Council of Texas, in 2015, nearly half of ERCOT’s grid was fueled by gas. Courtesy: ERCOT

“You wonder about some of the capacity that has been added,” he said. “If it were a rational economic market, you wouldn’t build that until there was indication that supply was tightening and you could return your investment.”

An Insidious Gas Transport Problem

Meanwhile, and perhaps more worryingly, market woes faced by generators are significantly complicating gas transport issues, noted Richard Kruse, vice president for regulatory affairs at Spectra Energy, the company that owns and operates the Algonquin Gas Transmission pipeline. For the last four years, the 1,129-mile pipeline that traverses New England, New York, and New Jersey has run at 100% capacity, Kruse said, and that has meant seasonal supply issues for generators in New England, which is increasingly relying on natural gas for power owing to its market structure.

“Change is coming fast,” he said. Ten years ago, the region banked on natural gas for 12% to 14% of its generation, but now it’s 60%, he noted, attributing it to the rapid phase-out of coal and nuclear capacity. Up to 30% of New England’s generating capacity could be retired by 2020, replaced largely with natural gas–fired power plants.`

“That’s great news for the gas industry,” but now, the region crippled by market volatility is suffering supply constraints. These stem from a stark lack of firm pipeline capacity commitments from generators that are struggling to keep plants profitable. “The end result is the markets in New England–and this is our experience pretty much across the nation—are relying on capacity rules and secondary transportation to get the gas to them,” he said. Without firm contracts for pipeline capacity, generators can be left with no means to receive gas on days when there is high demand.

This has resulted in sudden scarcity and price surges, Kruse said. For example, compared to the MISO, which sees winter peak wholesale power prices of $29.31/MWh, generators within the ISO New England region see skyrocketing prices of about $76.64/MWh owing to system constraints as local distribution companies pull back capacity.

To mitigate these issues, Spectra is developing Access Northeast, a project that is designed to upgrade the existing Algonquin Gas Transmission system and add regional liquefied natural gas assets in New England. The approach seeks to avoid overbuilding new pipeline infrastructure while still delivering up to 925,000 dekatherms per day beginning in late 2018.

Kruse also outlined a number of optimal services that could benefit the power sector, including a “no-notice” gas transportation service with a quick-start option, and reserved firm capacity that can be used on a “no-notice” basis any time during a gas day.

The Pains of Building New Gas Generation

Finally, building new gas power plants isn’t easy, stressed Peter Furniss, CEO of Footprint Power, a company that is putting up a 674-MW gas plant on the site of the former coal- and oil–fired power plant in Salem, Mass. The $1 billion plant, the first built in Massachusetts in more than 13 years, is slated to come online in June 2017—nearly a year later than planned, largely due to permitting hurdles and opposition.

To keep the process going, New Jersey–based Footprint Power ultimately struck a deal in 2014 with environmental group Conservation Law Foundation—an organization with which it had been in dialogue since the project was conceived, Furniss revealed—to reduce greenhouse gas emissions from the new Salem Harbor facility annually over its 40-year lifespan to meet state climate change mandates.

“The development process is an unending process,” Furniss said. “It is something that requires a great deal of discipline and requires that you keep going back to your repository of data to keep the process going.”

One way that his team minimized delays was to share Footprint’s goals early in the process with its broader stakeholder group. Communication was integral in reducing risks because it minimized local opposition and it eliminated barriers to assistance from interested parties, he said. It also served well to crystallize project elements early in the process to avoid costly changes later. “Projects with reduced risks are easier to finance at all stages of development,” he noted.

But larger, more under-addressed issues plague the industry, many arising from system complications, Furniss cautioned. “As an industry, we have legitimate gripes about the way our system is run. As a developer and an independent power producer [IPP], I’ve been battling three aspects of the rules: That they are unclear, inconsistent, and unpredictable,” he said. “It doesn’t matter which [regional transmission operator] you are in, I think we all struggle with this.”

At the heart of the issue, he said, is that the industry views itself in “silos”—IPPs versus utilities, for example—and that makes it hard to “attack the rules with any legitimacy.”

“It makes absolutely no sense for everyone to be living under uncertainty,” he said.

Sonal Patel, associate editor (@POWERmagazine, @sonalcpatel). Source: http://www.powermag.com/

No New Australian LNG Projects Doesn’t Mean No New LNG


LAUNCESTON, Australia, June 9 (Reuters) – Conventional wisdom in the liquefied natural gas (LNG) sector is that no new projects will be built for several years, given the vast cost can’t be reconciled with the current low prices.

This view has led some in the industry to predict that the market will flip back to a structural shortage sometime in the early to mid-2020s, once again sending prices soaring as new supply takes so long to be built and become operational.

The cancellation or deferment of investment decisions on several projects in Australia, Canada, the United States and elsewhere seems to perfectly illustrate the view that no new LNG will be coming to market once the plants currently under construction are completed.

The wave of LNG building in recent years has seen eight projects being built in Australia, with five now operating and the remaining three nearing completion, and five in the United States, the first of which has starting shipping cargoes.

This has helped drive LNG from a structural deficit to a surplus, with the attendant decline in Asia spot prices <LNG-AS> from a high of $20.50 per million British thermal units (mmBtu) to a record low of just $4 in April this year.

Long-term contract prices linked to crude oil have also suffered as Brent has slumped, further undermining the economics of new plants.


Australia’s biggest LNG operator, Woodside Petroleum , shelved plans to build the $30 billion Browse LNG project in Western Australia state in March, citing oversupply and low prices.

Royal Dutch Shell and Malaysia’s Petronas have also pushed back final investment decisions on greenfield LNG developments on Canada’s west coast, and progress has slowed on planned U.S. projects and those in frontier countries such as Mozambique and Tanzania.

The era of mega-LNG projects appears to be over, at least for now.

This point was underscored by Saul Kavonic, a senior analyst at consultants Wood Mackenzie, who told the Australian Petroleum Production and Exploration Association conference in Brisbane this week that the country’s wave of recent LNG projects had failed to meet hurdle rates.

The average breakeven cost for the recent projects, which will see Australia overtake Qatar as the world’s biggest supplier of the super-chilled fuel, is $12.60 per mmBtu, a price well above the current spot level and also most long-term oil-linked contracts.

However, while Kavonic said that building new projects is unviable in the current situation, Australian LNG producers can boost volumes if demand warrants increased supply.


The first way to do this is through de-bottlenecking existing plants, a process Kavonic said delivered an average 14 percent boost in capacity at LNG plants that have implemented the efficiency measures in the past.

An additional 4 million tonnes per annum of LNG is probable and a further 6 million possible from de-bottlenecking, Kavonic told the conference.

These are fairly significant numbers, as 10 million tonnes would represent an 11 percent increase in Australia’s eventual capacity and is just under half of Chinese annual demand.

The second way to boost capacity is through brownfield expansions, which Kavonic said typically cost about 30 percent less than building projects from scratch.

This could add more than 10 million tonnes in Australia, but Kavonic estimates that brownfield developments would require a price above $8 per mmBtu to be economically feasible.

A third way to boost capacity is backfill, which involves committing new gas to existing projects to allow them to continue operating beyond their expected and planned life.

While this doesn’t add new capacity, it prevents volumes from leaving the market, and Kavonic estimates that 15 million tonnes of capacity could be maintained by 2030 if companies adopt backfill policies.

What becomes clear is that there are substantial volumes of LNG that can come to the market in the coming years at considerably lower prices when compared to the huge cost of developing new plants and natural gas fields to supply them.

There are of course some fairly significant hurdles, the main one being the need for the various companies in the industry to put aside rivalries and work together to share infrastructure and establish joint ventures to supply natural gas to LNG trains.

“Boys and girls don’t like to share their train sets,” was how Kavonic put it, a jest that rings true when looking at the three adjacent coal-seam gas to LNG plants recently built at Gladstone, on Australia’s east coast.

These plants don’t share infrastructure even though it would have been more cost-effective for all concerned if they had jointly developed facilities such as pipelines, storage, jetties and power supply.

Perhaps the expected period of low prices in the next few years will encourage the sort of innovation and cooperation that would allow LNG producers to increase output at competitive costs should demand grow strongly in the 2020s.

Source: http://www.downstreamtoday.com/ 


Energy Policy Differences Between Trump and Clinton Are Black and White


The two probable major-party U.S. presidential candidates hold very different views on energy and climate. One intends to focus on expanding and developing America’s fossil-fuel industries, while the other plans to grow renewable energy and promote efficiency. Can you guess who’s who?

Fossil vs. Renewable

Donald Trump, the presumed Republican nominee, presented his “America-First Energy Plan” during a speech at the 2016 Williston Basin Petroleum Conference held in Bismarck, N.D., on May 26. Under a Trump administration, “American energy dominance will be declared a strategic economic and foreign policy goal of the United States,” he said.

Hillary Clinton, the leading candidate for the Democrats, has touted two major goals as part of her platform. They are to have more than half a billion solar panels installed across the country by the end of her first term, and to generate enough clean renewable energy to power every home in America within 10 years of taking office.

During Trump’s speech, he trumpeted vast oil and gas reserves that he says exist on federal lands. “We’re loaded! We didn’t even know it. We’re loaded! We had no idea how rich we were. We’re richer than all of ’em!” he exclaimed to a cheering crowd at the North Dakota Petroleum Council–hosted event.

Trump claimed that the U.S. has more natural gas than Russia, Iran, Qatar, and Saudi Arabia combined. However, based on OPEC’s 2015 Annual Statistical Bulletin, Trump’s assertion is far from true. While the bulletin does peg U.S. natural gas reserves ahead of Saudi Arabia’s, Iran is said to have more than twice as much as the U.S. Statistics show that Qatar has three times the U.S. reserves and Russia has five times as much.

Trump also claimed that the U.S. has 1.5 times more oil than all OPEC countries combined, which also doesn’t jibe with publicly available statistics. While the U.S. Energy Information Administration says U.S. crude oil and lease condensate proved reserves were in excess of 39 billion barrels in 2014, the OPEC bulletin says its reserves were 1.2 trillion barrels in 2014—more than 30 times the U.S. total.

Presumably, Trump is getting his statistics from recently announced energy advisor, North Dakota Congressman Kevin Cramer, but somewhere along the line the numbers seem to have been distorted.

Clean Power Plan

The candidates differ markedly in their environmental positions too. Clinton said she would make it a top priority to fight efforts to roll back the Clean Power Plan—the Environmental Protection Agency’s rule to cut carbon emissions from power plants by 32% below 2005 levels by 2030.

“I won’t let anyone take us backward, deny our economy the benefits of harnessing a clean energy future, or force our children to endure the catastrophe that would result from unchecked climate change,” Clinton said.

In contrast, Trump said his administration would focus “on real environmental challenges—not the phony ones that we’ve been looking at [under the Obama administration].”

As part of his 100-day action plan, Trump said he would rescind “all the job destroying Obama executive actions, including the Climate Action Plan and the Waters of the United States rule.”

Paris Climate Pledge

Trump made it clear that he isn’t interested in being a part of a worldwide movement to cut carbon emissions either.

“We’re going to cancel the Paris climate agreement,” he said, “and stop all payments of the Unites States’ tax dollars to the UN global warming programs.”

According to Clinton, her plan is designed to “deliver on the pledge President Obama made at the Paris climate conference last December—without relying on climate deniers in Congress to pass new legislation.” She claims her plan will reduce greenhouse gas emissions by up to 30% in 2025 relative to 2005 levels and put the country on a path to cut emissions more than 80% by 2050.

Energy Consumption

Clinton wants to cut energy waste in American homes, schools, hospitals, and offices by a third and make American manufacturing the cleanest and most efficient in the world. She also wants to reduce American oil consumption by a third through cleaner fuels and more efficient cars, boilers, ships, and trucks.

Trump didn’t announce any energy-efficiency goals as part of his America-First plan; his objectives seem to emphasize the supply side of the equation instead. He said he is going to ask TransCanada to renew its permit application for the Keystone pipeline, he’s going to lift moratoriums on energy production in federal areas, and he’s going to revoke policies that impose unwarranted restrictions on new drilling technologies.

“We will become and stay totally independent of any need to import energy from the OPEC cartel or any nations hostile to our interests,” Trump said.

Clinton is less anxious to drill in certain locations. She believes that as the nation transitions to a clean energy economy, it “must ensure that the fossil fuel production taking place today is safe and responsible and that areas too sensitive for energy production are taken off the table.” According to her campaign website, she “knows there are some places where we should keep fossil fuels in the ground or under the ocean.”


Environmental justice and climate justice are central priorities, according to Clinton. She believes air pollution, water pollution, and toxic sites are disproportionately impacting low-income communities and communities of color. Clinton intends to set a “national goal to eliminate lead poisoning as a public health risk within five years, create new economic opportunity by cleaning up the more than 450,000 toxic brownfield sites across the country, expand solar and energy efficiency solutions in low-income communities, and include the voices of community leaders, the environmental justice movement, and outside experts in taking on these challenges with a new Environmental and Climate Justice Task Force.”

Trump’s plan is to roll back at least some current regulations. “From an environmental standpoint, my priorities are very simple: clean air and clean water,” he said.

“Any regulation that’s outdated, unnecessary, bad for workers, or contrary to the national interest will be scrapped and scrapped completely,” said Trump. “Any future regulation will go through a simple test: Is this regulation good for the American worker? If it doesn’t pass this test, this rule will not be, under any circumstances, approved.”

While both candidates offer forceful sound bites, when it comes time for the new president to implement his or her energy policy, it will be interesting to see how the plan progresses. Only time will tell.

source: http://www.powermag.com/

Oil settles above $50 for first time in more than 10 months


Oil closed above $50 a barrel in New York for the first time in more than 10 months as U.S. crude stockpiles are estimated to have fallen for a third week, trimming a glut.

West Texas Intermediate oil rose 1.4 percent to the highest settlement since July 21. Inventories declined by 3 million barrels last week in the U.S., according to a Bloomberg survey before a report from the Energy Information Administration on Wednesday. Royal Dutch Shell Plc is repairing a key pipeline in Nigeria under very tight security, according to a person familiar with the operations. Earlier reports said work wasn’t proceeding on the link.

Crude has surged about 90 percent from a 12-year low in February amid unexpected disruptions and a continuous slide in U.S. output, which is under pressure from the Organization of Petroleum Exporting Countries’ policy of pumping without limits. Saudi Arabia will maintain the same level of production capacity until 2020 under a new economic reform plan approved by the government to reduce its reliance on oil.

“The path of least resistance for crude is still higher and outages in Nigeria and expectations of strong EIA data tomorrow are helping the trend,” said Clayton Rogers, an energy derivative broker at SCS Commodities Corp. in New Jersey. “I think the real story is just how range-bound this market is.”

WTI for July delivery rose 67 cents to close at $50.36 a barrel on the New York Mercantile Exchange. Prices are up 36 percent this year.

Energy Rally

Futures traded near the settlement after the industry-funded American Petroleum Institute was said to report U.S. crude supplies fell 3.57 million barrels last week. WTI traded at $50.37 at 4:38 p.m in New York. Total volume traded was 13 percent below the 100-day average.

Brent for August settlement rose 89 cents, or 1.8 percent, to $51.44 a barrel on the London-based ICE Futures Europe exchange. It was the highest close since Oct. 9. The global benchmark crude ended the session at a 52-cent premium to August WTI.

Energy companies accounted for nine of the ten biggest gainers on the Standard & Poor’s 500 Index. The S&P 500 Oil & Gas Exploration and Production Index climbed 2.7 percent to the highest level since November at the close of the day’s trading.

“My concern is that you’ve already built a lot of good news into the price,” said Bill O’Grady, chief market strategist at Confluence Investment Management in St. Louis, which oversees $4.3 billion. “We may soon have discounted all the positive news.”


Crude stockpiles at Cushing, Oklahoma, the delivery point for WTI and the biggest U.S. oil-storage hub, probably declined by 671,000 barrels last week, according to the median estimate in a Bloomberg survey. In the week ended May 27, nationwide inventories dropped by 1.37 million barrels to 535.7 million, according to the EIA.

The repairs in Nigeria were being carried out in two different sites of the Forcados pipeline, which was hit by explosions in February and again last week, said the person, who asked not to be named because of security concerns. Earlier Chief Financial Officer Simon Henry said the company had to withdraw repair crews last week after a second attack against the 48-inch export pipeline that links onshore storage tanks with an offshore port.

Gasoline Outlook

Gasoline futures fell amid speculation that demand for the fuel won’t meet expectations. U.S. refiners typically increase utilization this time of year after finishing maintenance as the peak-demand driving season commences. Consumption during the second and third quarters this year will average a record 9.5 million barrels a day, up from 9.48 million forecast in May, the EIA said ts monthly Short-Term Energy Outlook released Tuesday.

“The one bearish blot out there is gasoline,” O’Grady said. “Refineries were expected to run at about 95 percent of capacity to make gasoline, which would lead to further crude inventory declines. This might have been overoptimistic.”

July gasoline futures slipped 0.1 percent to $1.5871 a gallon, the lowest close since May 12. While the July contract declined, those for other months rose. The market is in contango, when prices for delivery today are lower than those in future months, which may signal weak near-term demand or rising supply.

Oil-market news:

“The much-anticipated rebalancing of supply and demand now seems within reach,” Trafigura Group Pte CEO Jeremy Weir said in the trading firm’s first-half report. Oil may never get back to $100 a barrel and current prices represent an opportunity to reset the industry’s cost base, said Shell Chief Executive Officer Ben Van Beurden.

Source: www.energyvoice.com

Commodities storming back into bull market


After four years of depressed prices for most commodities, especially gold, iron ore, coal, copper and oil, the end of the bear market seems closer than ever as raw materials continue to outperform bonds, currencies and equities.

Based on the Bloomberg Commodity Index, which tracks returns from 22 raw materials, everything from soybeans to diamonds have experienced an important recovery this year.

Oil is already back to $50 per barrel. A similar jump is visible in non-ferrous metals like copper, zinc and aluminum, to name a few.

As a result, the index is on track to close more than 20% above its low on Jan. 20, meeting the common definition of a bull market, even though it is still down almost 50% from the high reached in 2011.

While there are some specific commodities which may face some downside pressure like soybeans and sugar, an increasing number of experts — such as ABN Amro and Schroders Asset Management — are saying there is far more upside potential for other materials, mainly metals and energy.

Crude oil is already back to $50 per barrel. A similar jump is visible in non-ferrous metals like copper, zinc and aluminum, to name a few.

Canadian stocks are among those that have benefitted the most from the ongoing recovery. The S&P/TSX Composite Index climbed 0.6 per cent to 14,226.78 Friday, capping a 20% rally from a bear-market low of 11,843.11 on Jan. 20.

In barely four months, Canada’s mining and energy sectors have added More than Cdn$370 billion ($286bn) as oil prices climbed over 80% over that time, stoking growth in the export-oriented economy, the world’s 11th largest.

“Wild swings” ahead

Despite the positive figures, some remain cautious. Citigroup said last month that while commodities have “turned a corner,” the potential for wild swings in prices this year remains high.

“The past few years have demonstrated that changes in market sentiment can be abrupt and can affect both price direction and cross commodity and cross asset correlations,” Citi analysts wrote.

“We expect these persistent features of markets to start to dissipate,” the analysts added. “But the interrelated factors of changes in views about the Chinese economy and actual changes in the U.S. Fed’s monetary policy can directly and indirectly impact commodities, both with respect to expectations of global growth and of the relative value of the U.S. dollar.”

As predicted, Wall Street was higher on Monday morning, lifted mostly by energy stocks and a rebound in financial stocks, as investors awaited a speech by Federal Reserve Chair Janet Yellen for clues on when borrowing costs may rise.

source: http://www.mining.com/ 

Gas Turbine Market to Grow at 3.49% CAGR Driven by Power Generation Applications to 2020


One trend which will positively impact the gas turbine market is the regulations being enacted by governments worldwide with concerns about resource depletion, increase in harmful emissions, and stricter regulations for climate change mitigation bettering the focus on technologies that can produce power in a much cleaner and efficient manner. The analysts forecast global gas turbine market to grow at a CAGR of 3.49% during the period 2016-2020.

Complete report on gas turbine market spread across 106 pages, analyzing 6 major companies and providing 60 data exhibits is now available at http://www.rnrmarketresearch.com/global-gas-turbine-market-2016-2020-market-report.html.

According to the 2016 report, a key growth driver for gas turbine market is the increasing efficiency and durability of gas turbines. The increasing efficiency of gas turbines is projected to drive their adoption for power generation applications. Stringent carbon emission regulations worldwide; focus on high performance and lower power generating cost; and volatility in fuel costs are driving demand for highly efficient gas turbines.

Worldwide, power generation is undergoing a transformation from centralized systems to integrated networks due to growing reliance on distributed power generation systems. Distributed power technologies are less than 100 MW in size with the standard size being less than 50 MW, which is the limit permitted by distribution systems at distribution voltages.


The following companies are the key players in the global gas turbine market: Ansaldo Energia, GE, Kawasaki Heavy Industries, Mitsubishi Hitachi Power Systems, Siemens, and Solar Turbines. Other prominent vendors in the market are: MAN Diesel and Turbo, Motor Sich, Niigata Power Systems, OPRA Turbines and Power Machines.

Gas turbines are an essential part of distributed power technologies product portfolio along with diesel and gas reciprocating engines, solar panels, fuel cells, and small wind turbines. Thus, growth of distributed power systems will translate to an increased demand for gas turbines during the forecast period.

The use of gas turbines is increasing the world over in sync with the rising demand for global power and cleaner solutions. APAC countries such as China and India are expected to contribute significantly to the growth of the segment with a large number of ongoing power generation projects. The mobility segment mainly consists of aeronautic and marine applications of gas turbines and is predicted to be the fastest growing end-user segment in the market. The oil and gas industry, including all segments of the value chain like upstream, midstream, and downstream, use gas turbines for power generation. The midstream and downstream segments are likely to drive the global gas turbine market in the coming years. Order a copy of Global Gas Turbine Market 2016-2020 report @http://www.rnrmarketresearch.com/contacts/purchase?rname=582881.

Global Gas Turbine Market 2016-2020, has been prepared based on an in-depth market analysis with inputs from industry experts. The report covers the market landscape and its growth prospects over the coming years. The report also includes a discussion of the key vendors operating in this market. The report covers the present scenario and the growth prospects of the global gas turbine market for 2016-2020. The capacity additions of new gas turbines as well as aftermarket gas turbines in various end-user segments and the average price of various types of gas turbines have been considered in determining the market size.

Further, the gas turbine market report states that one challenge that could hinder market growth is the risk of volatile natural gas prices.

Source: http://www.prnewswire.com/

Austrailia: Qld exported more LNG in Q1 than Russia, report says


This was due to the ramp-up of production from APLNG and GLNG projects located on Curtis island in Queensland and the first cargo from Chevron’s Gorgon project in Western Australia.

Of note over the period was Queensland’s March quarter performance – exporting 3.8 Mt of LNG – more than the whole of Russia’s 2.5 Mt of LNG exports, the report said.

Queensland’s performance is extraordinary, from zero LNG exports as recently as 18 months ago to more than Russia already,” EnergyQuest CEO Graeme Bethune said in the report.

According to the report, Shell’s QCLNG project, also located on Curtis Island, shipped 31 cargoes in Q1 comprising 2.1 Mt, Santos’s GLNG project shipped 16 cargoes of nearly 1 Mt and the Origin Energy-Conoco Phillips project shipped 11 cargoes of 0.7 Mt.

LNG output is now Australia’s largest component of petroleum production.

Despite a 36% fall in average Australian LNG export prices due to the fall in oil prices, Australian LNG export revenue in Q1 of $4,469 million was only down slightly from Q1 2015, supported by the growth of export volumes, the report said.


LNG boosts Australia’s GDP

Australian Bureau of Statistics (ABS) data released on Wednesday confirms that strong LNG exports are a “rare source of growth” in Australia’s economy, the Australian Petroleum Production & Exploration Association (APPEA) said in a statement.

Oil and gas extraction rose by 5.1 per cent over the 2016 March quarter, following the record $17 billion in LNG exports in 2015.

APPEA Chief Executive Malcolm Roberts said Australia’s LNG projects will “deliver decades of economic growth, jobs and exports”.

In 2015, the seven LNG projects in Australia produced about 30 million tonnes of LNG,” Roberts said.

When these projects and the three projects under construction reach full output, Australia’s LNG exports will almost triple”.

By 2019, Australia will be the largest single exporter of LNG in the world,” according to Roberts.

For LNG to continue to be a pillar of the nation’s economy amid a depressed oil market, exploration and development must be fostered, not restricted,” he said.

Roberts added that capturing future growth and investment opportunities should be a “key aim” for both major parties during the Federal election campaign.

We need to hear much more from our political leaders about how they intend to encourage resource investment, increase competitiveness and build on a decade of extraordinary LNG investment,” he added.

Source: http://www.lngworldnews.com/ 

Iran says in talks with Rio, Glencore about copper projects


Iran is stepping up talks with potential foreign investors with an eye to developing its mining and metals industries according to Mehdi Karbasian, president of Imidro a state-owned group pushing for mine development in the country, Platts News reported on Wednesday.

The annual value of Iran’s mining and metals imports and exports only amount to $11.5 billion at the moment, but following the lifting of sanctions last year the country has ambitious plans saying potential revenues from the sector could be worth more than crude oil.

Speaking following the opening of a new Europe-Iran trade center in Berlin, Karbasian said Imidro recently held talks with Australia’s Rio Tinto about new investments in the Middle Eastern nation’s aluminum, steel, copper and gold industries.

Karbasian has also met with top brass from  European  commodities trading giants Glencore and Trafigura, and Germany’s Aurubis, the regions top copper producer and the world’s number one recycler of the metal:

“Glencore and China’s NFC already have business agreements to help develop Iran’s copper industry, Karbasian said earlier this year. Iran hopes to raise its copper concentrates output to as much as 2 million mt/year by 2025 in conjunction with partners, from some 200,000 mt/year at present, as part of a national development plan, he said.”

According to Imidro, Iran’s copper reserves accounts for 4% of the world’s total or roughly 2.6 billion tonnes and the country’s production represent 75% of the total for the Middle-East. National Iranian Copper Industries Company is listed on the Tehran Stock Exchange and is the country’s top non-oil exporter.

The country is also a leading lead and zinc producer and ranks number four in Asia behind China, Kazakhstan and India in terms of production. Iran’s zinc reserves are the world’s largest. There are only 15 operating gold mines in Iran, but expanding  precious metal mining received a boost in November 2014 with the commissioning of the Middle-East’s largest gold processing plant at the Zareh Shuran mine in the West Azerbaijan province to boost production from less than 30,000oz to over 200,000oz per year.

Iran in March inked deals South Korea and with China’s Sinosteel to build a massive aluminum smelter and plans to put out an international tender for a bauxite pipeline in Guinea, West Africa.

The discovery of two large coal and iron ore deposits in the Lut desert in central Iran was announced by the mines ministry last year.  The country is the number four supplier of iron ore to China, shipping some 15–20 million tonnes annually of domestic production of 45 million tonnes.

Imidro last month announced 17 development projects inside the country worth $1.2 billion. Mining represents 0.7% of the country’s GDP and the goal of the national development plan is to lift that to 4%.

There are approximately 5,500 mines in operation in Iran, with 90% owned by the state. Iran’s mining industry is uncompetitive despite very low labour costs because of a crippling lack of equipment and machinery due the the sanctions regime  Karbasian said in November: “Old and second-hand machineries are being used in many of the mines some of which have been used in other countries for over 50 years.”

Source: http://goo.gl/eDijhl 

Better combustion for power generation


In the United States, the use of natural gas for electricity generation continues to grow. The driving forces behind this development? A boom in domestic natural gas production, historically low prices, and increased scrutiny over fossil fuels’ carbon emissions. Though coal still accounts for about a third of US electricity generation, utility companies are pivoting to cleaner natural gas to replace decommissioned coal plants.

Low-maintenance, high-efficiency gas turbines are playing an important role in this transition, boosting the economic attractiveness of natural gas-derived electricity. General Electric (GE), a world leader in industrial power generation technology and the world’s largest supplier of gas turbines, considers gas-fired power generation a key growth sector of its business and a practical step toward reducing global greenhouse gas emissions. When burned for electricity, natural gas emits half the carbon dioxide that coal does. It also requires fewer environmental controls.


“Advanced gas turbine technology gives customers one of the lowest installed costs per kilowatt,” said Joe Citeno, combustion engineering manager for GE Power. “We see it as a staple for increased power generation around the world.”

GE’s H-class heavy-duty gas turbines are currently the world’s largest and most efficient gas turbines, capable of converting fuel and air into electricity at more than 62 percent power-plant efficiency when matched with a steam turbine generator, a setup known as combined cycle. By comparison, today’s simple cycle power plants (gas turbine generator only) operate with efficiencies ranging between 33 and 44 percent depending on the size and model.

GE is constantly searching for ways to improve the performance and overall value of its products. A single percent increase in gas turbine efficiency equates to millions of dollars in saved fuel costs for GE’s customers and tons of carbon dioxide spared from the atmosphere. For a 1 gigawatt power plant, a 1 percent improvement in efficiency saves 17,000 metric tons of carbon dioxide emissions a year, equivalent to removing more than 3,500 vehicles from the road. Applying such an efficiency gain across the US combined-cycle fleet (approximately 200 gigawatts) would save about 3.5 million metric tons of carbon dioxide each year.

In 2015, the search for efficiency gains led GE to tackle one of the most complex problems in science and engineering–instabilities in gas turbine combustors. The journey led the company to the Titan supercomputer at the Oak Ridge Leadership Computing Facility (OLCF), a US Department of Energy (DOE) Office of Science User Facility located at DOE’s Oak Ridge National Laboratory.

Balancing act

Simultaneously increasing the efficiency and reducing the emissions of natural gas-powered turbines is a delicate balancing act. It requires an intricate understanding of these massive energy-converting machines — their materials, aerodynamics, and heat transfer, as well as how effectively they combust, or burn, fuel. Of all these factors, combustion physics is perhaps the most complex.

In an H-class gas turbine, combustion takes place within 6-foot-long chambers at high temperature and pressure. Much like a car engine has multiple cylinders, GE’s H-class turbines possess a ring of 12 or 16 combustors, each capable of burning nearly three tons of fuel and air per minute at firing temperatures exceeding 1,500 degrees Celsius. The extreme conditions make it one of the most difficult processes to test at GE’s gas turbine facility in Greenville, South Carolina.

At higher temperatures, gas turbines produce more electricity. They also produce more emissions, such as nitrogen oxides (NOx), a group of reactive gases that are regulated at the state and federal levels. To reduce emissions, GE’s Dry Low NOx combustion technology mixes fuel with air before burning it in the combustor.

“When the fuel and air are nearly perfectly mixed, you have the lowest emissions,” said Jin Yan, manager of the computational combustion lab at GE’s Global Research Center. “Imagine 20 tractor-trailers full of combustible fuel-air mixture. One combustor burns that amount every minute. In the process, it produces less than a tea cup (several ounces) of NOx emissions.”

Such precise burning can lead to other problems, specifically an unstable flame. Inside a combustor, instabilities in the flame can cause deafening acoustic pulsations–essentially noise-induced pressure waves. These pulsations can affect turbine performance. At their worst, they can wear out the machinery in a matter of minutes. For this reason, whenever a new pulsation is detected, understanding its cause and predicting whether it might affect future products becomes a high priority for the design team.

Testing limits

In 2014, one such pulsation caught researchers’ attention during a full-scale test of a gas turbine. The test revealed a combustion instability that hadn’t been observed during combustor development testing. The company determined the instability levels were acceptable for sustained operation and would not affect gas turbine performance. But GE researchers wanted to understand its cause, an investigation that could help them predict how the pulsations could manifest in future designs.

The company suspected the pulsations stemmed from an interaction between adjacent combustors, but they had no physical test capable of confirming this hypothesis. Because of facility airflow limits, GE is able to test only one combustor at a time. Even if the company could test multiple combustors, access-visibility and camera technology currently limit the researchers’ ability to understand and visualize the causes of high-frequency flame instabilities. So GE placed a bet on high-fidelity modeling and simulation to reveal what the physical tests could not.

The company asked its team of computational scientists, led by Yan, to see if it could reproduce the instability virtually using high-performance computers. GE also asked Yan’s team to use the resulting model to determine whether the pulsations might manifest in a new GE engine incorporating DOE-funded technology and due to be tested in late 2015, less than a year away. GE then challenged Yan’s team, in collaboration with the software company Cascade Technologies, to deliver these first-of-a-kind results before the 2015 test to demonstrate a truly predictive capability.

“We didn’t know if we could do it,” Yan said. “First, we needed to replicate the instability that appeared in the 2014 test. This required modeling multiple combustors, something we had never done. Then we needed to predict through simulation whether that instability would appear in the new turbine design and at what level.”

Such enhanced modeling and simulation capabilities held the potential to dramatically accelerate future product development cycles and could provide GE with new insights into turbine engine performance earlier in the design process instead of after testing physical prototypes.

But GE faced another hurdle. To meet the challenge time frame, Yan and his team needed computing power that far exceeded GE’s internal capabilities.

A computing breakthrough

In the spring of 2015, GE turned to the OLCF for help. Through the OLCF’s Accelerating Competitiveness through Computational Excellence (ACCEL) industrial partnerships program, Yan’s team received a Director’s Discretionary allocation on Titan, a Cray XK7 system capable of 27 petaflops, or 27 quadrillion calculations per second.

Yan’s team began working closely with Cascade Technologies, based in Palo Alto, California, to scale up Cascade’s CHARLES code. CHARLES is a high-fidelity flow solver for large eddy simulation, a mathematical model grounded in fluid flow equations known as Navier-Stokes equations. Using this framework, CHARLES is capable of capturing the high-speed mixing and complex geometries of air and fuel during combustion. The code’s efficient algorithms make it ideally suited to leverage leadership-class supercomputers to produce petabytes of simulation data.

Cascade’s CHARLES solver can trace its technical roots back to Stanford University’s Center for Turbulence Research and research efforts funded through DOE’s Advanced Simulation and Computing program. Many of Cascade’s engineering team are alumni of these programs. Although the CHARLES solver was developed to tackle problems like high-fidelity jet engine simulation and supersonic jet noise prediction, it had never been applied to predict combustion dynamics in a configuration as complex as a GE gas turbine combustion system.

Using 11.2 million hours on Titan, members of Yan’s team and Cascade’s engineering team executed simulation runs that harnessed 8,000 and 16,000 cores at a time, achieving a speedup in code performance 30 times greater than the original code. Cascade’s Sanjeeb Bose, an alumnus of DOE’s Computational Science Graduate Fellowship Program, provided significant contributions to the application development effort, upgrading CHARLES’ reacting flow solver to work five times faster on Titan’s CPUs.

Leveraging CHARLES’ massively parallel grid generation capabilities — a new software feature developed by Cascade — Yan’s team produced a fine-mesh grid composed of nearly 1 billion cells. Each cell captured microsecond-scale snapshots of the air-fuel mix during turbulent combustion, including particle diffusion, chemical reactions, heat transfer, and energy exchange.

Working with OLCF visualization specialist Mike Matheson, Yan’s team developed a workflow to analyze its simulation data and view the flame structure in high definition. By early summer, the team had made enough progress to view the results: the first ever multicombustor dynamic instability simulation of a GE gas turbine. “It was a breakthrough for us,” Yan said. “We successfully developed a model that was able to repeat what we observed in the 2014 test.”

The new capability gave GE researchers a clearer picture of the instability and its causes that couldn’t be obtained otherwise. Beyond reproducing the instability, the advanced model allowed the team to slow down, zoom in, and observe combustion physics at the sub-millisecond level, something no empirical method can match.

“These simulations are actually more than an experiment,” Citeno said. “They provide new insights which, combined with human creativity, allow for opportunities to improve designs within the practical product cycle.”

With the advanced model and new simulation methods in hand, Yan’s team neared the finish line of its goal. Applying its new methods to the 2015 gas turbine, the team predicted a low instability level in the latest design that was acceptable for operation and would not affect performance. These results were affirmed during the full-scale gas turbine test, validating the predictive accuracy of the new simulation methods developed on Titan. “It was very exciting,” Yan said. “GE’s leadership put a lot of trust in us.”

With the computational team’s initial doubts now a distant memory, GE entered a world of new possibilities for evaluating gas turbine engines.

The path forward

Validation of its high-fidelity model and the predictive accuracy of its new simulation methods are giving GE the ability to better integrate simulation directly into its product design cycle. “It’s opened up our design space,” Yan said. “We can look at all kinds of ideas we never thought about before. The number of designs we can evaluate has grown substantially.”

Coupled with advancements in other aspects of gas turbine design, Citeno projects the end result will be a full percentage-point gain in efficiency. This is important to GE’s and DOE’s goal to produce a combined-cycle power plant that operates at 65 percent efficiency, a leap that translates to billions of dollars a year in fuel savings for customers. A 1 percent efficiency gain across the US combined-cycle fleet is estimated to save more than $11 billion in fuel over the next 20 years.

“The world desperately needs higher-efficiency gas turbines because the end result is millions of tons of carbon dioxide that’s not going into the atmosphere,” said Citeno, noting that in the last 2 years, more than 50 percent of gas turbines manufactured at GE’s Greenville plant were exported to other countries. “The more efficient the technology becomes, the faster it gets adopted globally, which further helps to improve the world’s carbon footprint.”

Internally, GE’s experience with the OLCF’s world-class computing resources and expertise helps the company understand and evaluate the value of larger-scale high-performance computing, supporting the case for future investment in GE’s in-house capabilities. “Access to OLCF systems allows us to see what’s possible and de-risk our internal computing investment decisions,” Citeno said. “We can show concrete examples to our leadership of how advanced modeling and simulation is driving new product development instead of hypothetical charts.”

Building on its success using Titan, GE is continuing to develop its combustion simulation capabilities under a 2016 allocation awarded through the DOE Office of Advanced Scientific Computing Research (ASCR) Leadership Computing Challenge, or ALCC, program. As part of the project, GE’s vendor partner Cascade is continuing to enhance its CHARLES code so that it can take advantage of Titan’s GPU accelerators.

“A year ago these were gleam-in-the-eye calculations,” Citeno said. “We wouldn’t do them because we couldn’t do them in a reasonable time frame to affect product design. Titan collapsed that, compressing our learning cycle by a factor of 10-plus and giving us answers in a month that would have taken a year with our own resources.”

Story Source:

The above post is reprinted from materials provided by DOE/Oak Ridge National Laboratory. Note: Materials may be edited for content and length.

Three years of painful cuts sets markets up for serious supply crunch


According to data from Rystad Energy, overall global oil output will fall this year as natural depletion overwhelms all new sources of supply. But the deficit will only widen in the years ahead due to the dramatic scaling back in spending on new exploration and development.

Statoil says that global capex is set to fall for two years in a row, and is on track to fall for a third year in 2017 as more spending cuts are likely. “For the first time in history, we’ve seen cutting of capex two years in a row and potentially we risk a third year as well for 2017,” Statoil’s Chief Financial Officer Hans Jakob Hegge told Bloomberg in a recent interview. “It might be that we see quite a dramatic reduction in replacing the capacity and of course that will have an impact, eventually, on price.”

Oil companies are making painful cuts to spending, which will translate into much lower production than expected in the years ahead.

Although markets have dealt with the supply overhang for the better part of two years, the surplus could flip to a deficit as early as this year, as declines exceed new sources of production by a few hundred thousand barrels per day. That widens to more than a million barrels per day in both 2017 and 2018. To be sure, there are extremely large volumes of oil sitting in storage, which will take a few years to work through. That will prevent any short-term price spike even if depletion surpasses new production. But Statoil’s CFO said the world could start to see supply problems by 2020.

According to a separate report from SAFE, a Washington-based think tank, the oil industry has cut somewhere around $225 billion in capex in 2015 and 2016, which will lead to global supplies 4 million barrels per day lower in 2018-2020, compared to what market analysts expected as of 2014.

Of course, these figures are not inevitable. A sharp rise in oil prices would spur new investment and new drilling. In other words, deficits create profit opportunities for drillers, ushering in new supplies. The price acts as a self-correcting mechanism.

The problem is that, unlike many other industries, resource extraction is extremely volatile, with supply responses very delayed. Many oil projects, after all, take years to develop. Supply overshot demand, crashed prices, and in response, supplies will undershoot demand in the next few years. The industry has always suffered from booms and busts, and there is little reason to think that it will change, at least in the short run.

But we tend to have a myopic view on what to expect. When oil prices go up, people buy fuel efficient cars. When they go down, SUVs are back in style. When the world is dealing with too much supply, market watchers predict oil prices will stay low for years to come. If spot oil prices suddenly rise, forecasts are revised sharply upwards.

Here’s another example: the WSJ reports that oil prices are entering a “sweet spot,” a range between $50 and $60 per barrel that could finally be good for the global economy – low enough to provide consumers with a bit of a stimulus, but high enough to keep the industry and capital spending afloat. Also, crude at $50, as opposed to $30, can provide a bit of inflation to the deflation-beset economies in Europe and Japan. “Crude between $50 and $60 would be the absolute sweet spot,” Mark Watkins, regional investment manager at U.S. Bank Wealth Management, told the WSJ. “Everybody wins there.”

That is all well and good, but who expects oil to trade between $50 and $60 for any lengthy period of time? If there is one thing that we have learned over the past two years, it is that nobody has a crystal ball on prices. And if the industry indeed cuts capex for three consecutive years, at a time when demand continues to rise, the one thing we can be sure of is more volatility.

source: Written by

Iron ore price back below $50


On Thursday  the Northern China benchmark iron ore price dipped to just below the $50 per dry metric tonne level for the first time since February according to data supplied by The Steel Index.

Iron ore is down 27.4% from its April high near $70, but is still trading 16% higher than at the start of they year.

The correction is the result of near and longer-term supply and demand dynamics (in short: rising output in Australia and slowing demand in China) and many factors are  stacked against a seaborne iron ore price above $50:

  • The price spike this year and particularly since March was purely a speculative bubble and not an indicator of improving demand
  • Chinese port stocks above 100 million tonnes for the first time since February last year is evidence of opportunistic buying and slack in the market
  • As much as 50m tonnes steel capacity came back online this year, but China’s swing steelmakers’ margins are shrinking fast and they could exit the market just as quickly
  • Beijing is continuing its program of eliminating chronic overcapacity in heavy industry which goes hand-in-hand with stricter pollution controls
  • After three decades of growth China’s own steel industry association said steel output already reached its peak in 2014
  • US and other countries’ anti-dumping policies mean Chinese blast furnaces can’t export their way out of trouble
  • China’s accumulated steel output will top 10 billion tonnes this year, providing a huge reserve of scrap
  • With more than 200m tonnes of capacity closed in three years, the remaining domestic Chinese miners may hang on for longer
  • Global output is still growing – an estimated 180 million tonnes of additional supply will enter seaborne trade through 2020
  • Additional tonnage is on the left of the cost-curve – cash costs at the Big 3 have been cut by half since 2012 and are heading below $10 a tonne
  • Roy Hill is ramping up, Vale’s S11D is on target for end-2016, Rio Tinto’s Silvergrass will take less than a year to build and further out the likes of Simandou, Zanaga and Central Eyre (not to mention a resurgent Iran) could fill any gaps opening up
  • Record-low freight rates have shrunk the differential between FOB and landed costs, removing another layer of potential per-tonne-profit
  • Some marginal miners encouraged by $50-plus prices restarted production and a chunk of this supply is hedged
  • Once the number three exporter, India has lifted export duties for  low-grade ore and may soon do the same for 58% Fe and up


    Even before the recent drop, the consensus forecast of analysts polled by FocusEconomics was a sub-$50 average during the second quarter. Of the 17 analysts polled the most bearish was JP Morgan at an average of just $38, while even the most optimistic, Oxford Analytics saw the price topping out at $55.The median forecast for 2017 is even more pessimistic at $44.80 over the course of the year according to FocusEconomics data.

    Source: http://www.mining.com/ 

U.S. NatGas Consumption Projected to Rise 21 Percent by 2040


Power generation will account for 34 percent of the growth in natural gas consumption between 2015 and 2040, the U.S. Energy Information Administration(EIA) said Thursday.

During the 25-year period, natural gas consumption in the U.S. will rise 1 percent a year, from 28 trillion cubic feet (Tcf) in 2015 to 34 Tcf in 2040, according to EIA’s report.


“The industrial and electric power sectors make up 49% and 34% of this growth, respectively, while consumption growth in the residential, commercial, and transportation sectors is much lower,” the report stated. “Energy-intensive industries and those that use natural gas as a feedstock, such as bulk chemicals, make up most of the increase in natural gas consumption.”

The growth stems primarily from low natural gas prices. According to the report, natural gas prices are projected to remain at or below $5 per million British termal units ( MMBtu) through 2040 (in 2015 dollars). Henry Hub spot prices averaged $2.62 per MMBtu in 2015, the lowest annual average since 1995. Gas prices, though, will rise through 2040, primarily due to rising demand for exports of liquefied natural gas (LNG).

The amount of natural gas used for power generation reached an all-time high last year, and EIA officials are projecting natural gas will overtake coal as the leading source of U.S. power generation in 2016. To comply with the carbon limits of the Clean Power Plan, which has been stayed by the U.S. Supreme Court, natural gas is expected to displace much of the nation’s coal-fired generation.

Source: http://www.power-eng.com/

Report: Oman ups tax on LNG companies


The state of Oman has increased its tax on liquefied natural gas (LNG) companies, according to local media reports.

The Times of Oman reported on Thursday that the tax has been raised from 15% to 55% in a joint meeting of the State Council and Majlis Al Shura, the country’s Consultative Council.


Additionally, the Omani newspaper said that Oman approved a 35 percent tax on petrochemical firms. The joint session resulted in a 63 percent vote for the increase of the petrochemical tax, the report said.

The decision comes on the back of OMR4.5 billion budget deficit. Despite spending cuts and tax increases, Oman’s revenue was severely hit by the drop in oil and gas prices.

Oman exports chilled gas through Oman LNG, a joint venture company established by a Royal Decree in 1994. The company owned 51 percent by the government, exports LNG from its terminal in Qalhat near Sur with a 10.4 mtpa capacity.

LNG World News contacted both Oman LNG and Shell that owns a 30 percent stake in the company, seeking comment on the matter, however, no responses have been received by the time this article was published.

Other shareholders in Oman LNG include Total (5.54%) Mitsubishi Corp. (2.77%), Partex (Oman) Corp (2%), Korea LNG (5%), Mitsui & Co. (2.77%) and Itochu Corporation with a 0.92% stake.

Source: http://www.lngworldnews.com/ 

World Better Forget About $100 Crude Coming Back, Norway Says


That’s the clear message from Norway’s petroleum and energy minister. Brent crude has surged more than 70% from a 12-year low earlier this year as a global glut shows signs of easing, bringing relief to oil companies and producing countries like Norway, which have been pummeled by the worst market downturn in a generation. While it’s “quite obvious” that the oil market will rebalance, it doesn’t mean Norway is planning — or even hoping — for prices to go back to what they were, Tord Lien said in a Bloomberg TV interview at the ministry’s offices in Oslo. “It’s better to plan for $60 and let the people who want to hope for $100, hope for $100,” he said. “We saw oil prices hitting $140 a barrel, and that does not contribute to economic growth. So therefore I’m not hoping for it.”

The collapse in crude prices has put Norway, Western Europe’s biggest oil and gas producer, at a crossroads, with investments in its offshore industry falling the most since 2000 and the government for the first time dipping into its $850 billion sovereign wealth fund to plug budget holes.

Even as 40,000 jobs disappeared in two years, the Nordic country resisted deploying drastic measures, like tax breaks for the oil industry introduced in the UK. The Norwegian petroleum-tax system, which includes a top tax of 78% but offers generous deductions for exploration and development spending, is “the best” there is and remains attractive because of its stability, Lien said.


Virgin Territory

Norway has instead kept offering new acreage to explorers, such as new licenses in a virgin area of the Arctic Barents Sea along the maritime border with Russia as recently as last week. It was the first time Norway opened entirely new blocks to the industry in more than 20 years. After crude production has dropped by half since a 2000 peak and as exploration results hit an almost 10-year low in 2015, the Nordic country is betting on the Barents Sea to help it maintain output in the coming decades.

Both Norwegian authorities and the companies involved “have a strong belief in the possibility of finding significant resources in the Barents Sea,” Lien said Tuesday.

Environmental Groups

Norway’s petroleum minister, himself a native of the country’s high north, hit back at environmental organizations’ criticism that it was unwise to open new swaths of the Arctic to exploration because offshore oil and gas in this region, usually more expensive to extract than in other areas, will have to remain in the ground if the world is to succeed in limiting global warming to less than 2° Celsius.

“To state that all the oil and gas resources in the Barents Sea aren’t profitable does not have any scientific backing,” Lien said. “A huge part of the supply today comes out of offshore resources and huge fields that are in decline already.” Just to maintain production at today’s level 10 to 15 years from now “demands huge investments in oil and gas production.”

While the government has been willing to accept the postponement of new projects offshore Norway during the current downturn, such as the Johan Castberg oil field in the Barents Sea, it will continue to demand that oil companies maintain investments designed to maximize production from existing deposits and where decisions are time-sensitive because of existing infrastructure, Lien said. One example is Statoil ASA’s Snorre 2040 project, designed to extract an additional 200 MMbbl of oil from the Snorre field in the North Sea.

Producers in Norway must “make sure that no resources in place on the Norwegian continental shelf are wasted due to short-term decisions,” he said. “The companies involved in Snorre 2040 know what we expect them to do. As always, I do expect the companies to follow up on the clear messages that we have given to them.”

source : http://www.oilandgaspeople.com

New highly profitable acid mine water solution unveiled


KRUGERSDORP (miningweekly.com) – A process has been developed that yields handsome profits by converting acid mine water into valuable fertiliser materials.

The process removes all of the total dissolved solids and converts them into saleable products.

“The whole treatment cost is zero,” Trailblazer Technologies director John Bewsey told Creamer Media’s Mining Weekly Online while putting the company’s pilot plant through its paces, in Krugersdorp. (Also watch attached Creamer Media video). Treating 15 megalitres of acid mine drainage (AMD) a day yields 49 000 t of high-value potassium nitrate and 24 000 t of ammonium sulphate. Potassium nitrate used in fertiliser is retailing for R15 000/t and Trailblazer will market it at R11 500/t. “We’re left with useable water at no cost and the whole process turns in a very handsome profit,” said Bewsey, who envisages funders being attracted by the scheme’s 30% return on investment. Trailblazer’s model is to build plants in partnership with funders and enter into contracts with mining companies to treat their AMD. It envisages funders making good profits, mines having the AMD problem solved and farmers being shielded from sodium damage. “It’s a complete win-win,” Bewsey commented. It would also save taxpayers the R12-billion that Water Minister Nomvula Mokonyane announced last week would be needed to turn AMD into safe water for commercial use as either industrial or potable water. The Minister chose the old south-west vertical shaft area of the dormant East Rand Proprietary Mines for the launch of the process to remove the sulphates. Bewsey described the department’s wasting of sulphate to form gypsum as “not the brightest of ideas”.  Instead, Trailblazer would use an alkali like soda ash to produce potassium nitrate for highly profitable sale into agriculture.


ROBBIE ROBINSON Bewsey explained that Trailblazer Technologies had added on to an original idea put forward in 1996 by the late Dr RE (Robbie) Robinson, who died in December at the age of 86. Robinson’s zero-cost plan for AMD was drawn up 20 years ago for the now stricken Grootvlei gold mine, on the East Rand. It involved moving away from the process of adding large quantities of lime into the AMD, precipitating it and allowing the overflow to go into the local Blesbokspruit. Instead, the visionary chemical engineer with distinguished involvement in minerals beneficiation spanning more than 60 years and a passion for linking mining and agriculture, formed an association with a company specialising in the ion exchange method and engaged previously disadvantaged technikon students to develop a new process that made use of the ion-exchange resin that Trailblazer Technologies is now using at its Krugersdorp plant. In the Grootvlei case, the resin removed the ferric oxide and the acid and was easily regenerated by eluting it with ammonia and producing ammonium sulphate for fertiliser. The red ferric oxide was very saleable along with nigh nuclear-grade uranium as well as cobalt, copper and nickel oxides.

Moreover, the virtually distilled water was earmarked for agricultural irrigation. Taking all this into account, the Grootvlei gold mine would have been put into a position to treat its AMD at zero cost, with Robinson’s innovative new process opening up agricultural pursuits for the people of the nearby informal settlement. However, the Department of Water Affairs broke Robinson’s heart when it opted instead for a far more expensive R10-million alternative that fell flat on its face, had to be discontinued and probably contributed to Grootvlei’s demise, along with the subsequent ignominious Aurora liquidation debacle. Now the department is again looking to a far more expensive long-term solution, which will be a major cost centre rather than the lucrative profit centre it could be through the sale of recovered fertiliser chemicals.

Source: http://www.miningweekly.com/

Taking the Pulse of Combustion


In the last 30 years, there has been significant regulatory pressure for gas turbine manufacturers and users to reduce nitrogen oxide (NOx) emissions.

The Canadian government led the way in 1992 with the Canadian Council of Ministers of the Environment’s (CCME) National Emission Guidelines for Stationary Combustion Turbines. The United States and the European Union (EU) both followed suit in the mid 2000’s with the release of the US Environmental Protection Agency’s (EPA) National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines and the EU’s Large Combustion Plant Directive respectively.

In response to these regulatory initiatives, gas turbine manufacturers initially turned to water and steam injections (Wet Low Emission technology) during the combustion process as the methodology for achieving the necessary reductions. However, as low emission requirements have increased in the last ten years, manufacturers have had to turn to alternative reduction methodologies, the two most popular of which have been lean-burn and dry low NOx designs.



In the case of both the lean-burn and dry low NOx designs, lower emissions have been achieved through the use of lower fuel-to-air ratios. However, the low fuel-to-air ratio has also left these turbines more prone to coupled acoustic/heat release pressure oscillations as a result of minor operational instabilities. While the magnitude of these oscillations may be low, even small fluctuations less than 1 psi (0.069 bar) can cause structural vibrations that result in high cycle fatigue in metal parts downstream of the combustors such as nozzles, baskets, transition pieces and blades.


In order to address this problem, the industry has developed combustion instability monitoring systems that employ combustion chamber pressure sensors. The output of these sensors is monitored by a dedicated data acquisition system. The system records pressure fluctuations for turbine tuning and alarms either the operator or the turbine controller of out-of-limits pressure fluctuations.

Piezoelectric pressure sensors are AC-coupled gauges that measure only dynamic pressure and have come to be widely used for this application. Initially, ground-isolated integrated electronic piezoelectric (IEPE) pressure sensors were installed in hundreds of turbines. While the integrated electronics allowed for amplification of the signal, the remote sensor (IMI Sensors Models 102M205 and 121A44) had a distinct disadvantage of only having a temperature tolerance of 250 °F (121 °C). As a result, the sensors had to be mounted in an ambient temperature environment external to the turbine containment area. Given the large acoustic volume between the sensor and the combustion chamber, the sensors were employed in “semi-infinite” coil systems that attenuated standing waves, but also limited the frequency range of the system. In addition, the standing waves in the gas volume between the sensor face and the combustion process caused both attenuation and amplification at various acoustic frequencies.

The performance trade-off of the IEPE sensor drove the industry to develop a pressure sensor that could be moved closer to the combustion process in order to expand the frequency range of the sensor. The first embodiment of the effort was the close coupled pressure sensor (IMI Sensors Model EX171M01) that had a temperature tolerance of 500 °F (260 °C) and a charge mode output. The sensor could be mounted inline on an “infinite” coil system. This system achieved substantial improvements in the measurement bandwidth.



The most recent effort has resulted in the development of on-turbine pressure sensors (IMI Sensors Model 176A02) in order to further reduce the acoustic volume between the sensor and combustor. Built to withstand temperatures up to 1200 °F (650 °C) with advanced crystal technology, the sensor can now be mounted directly on the combustor basket to provide 24/7, consistent, reliable combustion dynamics data so that tuning changes can be made at any time.

The sensors have been specially designed with case isolation and differential output, to reduce electromagnetic interference (EMI) issues to an absolute minimum. This on-turbine mounting has led to the sensors requiring hazardous area certification as they are now operating in potentially-explosive environments.

In the case of PCB Piezotronics, the new crystal technology, UHT-12™, features:

  • Absence of pyroelectric noise spikes up to 1200 °F (650 °C).
  • Sensitivity that remains more consistent over a wide temperature change.
  • Shear mode crystals isolated from base strain & transverse measurement errors.
  • Wide operating frequency range

In conclusion, the development of these pressure sensors is enabling turbine manufacturers to continue reducing NOx emissions without jeopardizing the integrity of the components downstream of the combustors. This technology is being utilized by not only turbine manufacturers, but also power plants, aftermarket service companies and system integrators that specialize in monitoring systems.


Meredith Christman is the product marketing manager for the IMI Division of PCB Piezotronics

Source: http://www.power-eng.com/

EIA: Carbon Dioxide Emissions from Power Generation Lowest since 1993



Carbon dioxide (CO2) emissions from electricity generation totaled 1,925 million metric tons in 2015, the lowest since 1993 and 21% below their 2005 level. A shift on the electricity generation mix, with generation from natural gas and renewables displacing coal-fired power, drove the reductions in emissions.

Total carbon dioxide emissions from the electric power sector declined even as demand for electricity remained relatively flat over the previous decade. In both 2013 and 2014, total electricity sales and electricity-related CO2 emissions increased. But in 2015, both sales and emissions fell. In 2015, warm winter temperatures reduced the demand for electricity, lessened the need to bring marginal generators online, and lowered natural gas prices. During seven months of 2015, electricity generated from natural gas exceeded coal generation.

Electricity generation and its resulting emissions are primarily determined by the available capacity and relative operating costs of the different technologies. Recent capacity additions have favored natural gas and renewable energy, while retirements have been mostly coal units. In recent years, the drop in natural gas prices, coupled with highly efficient natural gas-fired combined-cycle technology, made natural gas an attractive choice to serve baseload demand previously met by coal-fired generation. Coal-fired generation has decreased because of both the economics driven by cost per kilowatthour compared to that of natural gas and because of the effects of increased regulation on air emissions.


Recent shifts in the electricity generation mix have implications for both total energy consumption and energy-related CO2 emissions. Coal plants tend to have relatively low thermal efficiency compared to plants using combined-cycle technology fuelled by natural gas. Although there is some variation across individual plants, in general a coal plant consumes more energy than a combined-cycle natural gas plant to produce the same amount of electricity. Also, coal’s carbon content per unit of energy is nearly twice that of natural gas. Considering both the higher thermal efficiency of generators and lower carbon content of fuels, electricity generation using natural gas emits roughly 40% of the carbon dioxide that would be emitted from a coal-fired unit producing the same amount of electricity.


Other changes in the electric generating mix have also worked to reduce CO2 emissions. Renewable energy sources are gaining an increasing share of generation, driven primarily by increases in wind and solar capacity. Nuclear generation was relatively flat over the past decade but remains the single largest source of generation without CO2 emissions. Together, renewables and nuclear provided about 33% of overall U.S. electricity production in 2015, the highest share on record.

Source: http://www.eia.gov/
Principal contributor:
Channele Wirman

Report: Russia’s iron ore mining industry to expand with increase in production and exports


Iron ore production in Russia is estimated to grow to 115.1 million tonnes (Mt) in 2020 driven by new projects such as Bystrinskoye and Sobstvenno-Kachkanarskoye, says a report by Timetric.

Entitled ‘Iron Ore Mining in Russia to 2020‘, the report highlights that Russia’s vast 25 billion tonnes (Bt) iron ore reserves are the world’s third largest. The country was also the leader in iron ore production in Europe in 2014 and among the top five global producers, with a production of 105Mt.

Exports of iron ore and concentrate are estimated to be 24.8Mt by 2020, representing a compound annual growth rate (CAGR) of 3.6% after suffering a 10.9% fall in 2014. Ukraine’s decreasing contribution to the international steel market helped increase Russia’s exports of products from the metal, leading to a 2.7% increase in iron ore consumption at 87.5Mt in 2014.

“Exports of iron ore and concentrate are estimated to be 24.8 million tonnes by 2020.”

Timetric’s report further mentions that the iron ore deposits are primarily concentrated in the Ural region, Moscow (Tula region), north-west Russia and Siberia with central Russia being the key producer followed by Ural and Siberia. The country’s iron ore reserves accounted for 13.3% of the global total in 2015.

The key players in iron ore production in Russia are Metalloinvest MC LLC, Severstal Group, and Evraz Group SA. The mining industry’s main authorities are the Ministry of Natural Resources and Environment of the Russian Federation, and the Federal Agency on Mineral Resources.

Russia’s rich mineral resources include copper, iron ore, gold, diamond, coal, nickel, vanadium, titanium sponge, tin, tungsten, potash, sulphur, silicon, rhenium and fluorspar.


Oil rally seen having more to go as millions of barrels are lost


MELBOURNE, Australia (Bloomberg) — Oil prices are yet to reflect all of the millions of barrels of crude lost to supply disruptions, according to Australia & New Zealand Banking Group Ltd.

Almost 2.5 MMbpd of supplies have been removed from the oil market this year because of outages from Canada to Nigeria, with most of them occurring over the past month, ANZ analyst Daniel Hynes wrote in a report dated May 19. The disruptions are not only set to remain in place, but intensify over the coming weeks, according to the bank.

“The fact that oil hasn’t pushed through $50/bbl suggests the market is discounting the impact of the disruptions,” the analyst wrote in the report. “As these issues linger on, we expect an increasing supply risk premium will price into the market.”

Brent crude, the benchmark for more than half the world’s oil, has surged more than 75% from a 12-year low earlier this year as attacks on pipelines in Nigeria to Colombia, wildfires in Canada and a slowdown in U.S. output help curb a global glut. While those outages persist, a cash-strapped energy industry, ongoing political crises and a worsening drought threaten to cut a “significant” part of OPEC member Venezuela’s 2.5 MMbopd production capacity, according to ANZ.

Brent futures traded down 1.6% at $48.17/bbl on the London-based ICE Futures Europe exchange at 11:14 a.m. Singapore time. West Texas Intermediate crude, the U.S. benchmark, was 1.4% lower at $47.51 on the New York Mercantile Exchange.


Venezuela Crisis

Halliburton Co. and Schlumberger Ltd. have curbed activity in Venezuela due to lack of payment during the worst financial crisis in the nation’s oil industry. The Latin American nation with the world’s largest oil reserves relies on crude shipments for 95% of export revenue, and requires a higher price than almost every other member of the Organization of Petroleum Exporting Countries to balance its budget.

In Nigeria, militants are again blowing up the pipelines that criss-cross the mangrove swamps of the nation’s Niger River delta, reducing oil output to the lowest in almost three decades. Meanwhile, wildfires at the heart of Canada’s energy industry has almost doubled over the past week, ravaging an area five times bigger than New York City.

Prices haven’t risen more because crude inventories are “so high” and refiners can rely on stockpiles, Jeffrey Currie, the global head of commodities research at Goldman Sachs Group Inc., said earlier this week. A decline in production driven by the unexpected supply disruptions, as well as sustained demand, have resulted in a “sudden halt” to the global glut, the bank had said in a report dated May 15.

source: http://www.worldoil.com/

UK gas extends advantage over coal for power generation


Despite relatively flat gas and power prices, the near-term competitiveness of gas as fuel for power generation has been improved in recent weeks by increases in coal prices, an analysis by S&P Global Platts showed.

The 90-day CIF ARA thermal coal increased from $46.40/mt to $48.70/mt between May 6 and 13.

In the same time period, the NBP and UK power front-month contracts remained nearly flat, drifting from 29.30 pence/therm to 29.05 p/th and GBP32.20/MWh to GBP32.60/MWh, respectively.

Despite little change in flat prices, dearer coal has substantially improved gas’ competitiveness as a fuel for power generation.

One proxy for the competitiveness of gas against coal is the Coal Switching Price Indicator (CSPI), which approximates the threshold price for gas below which it is a cheaper input for power generation than coal.

By extension, if the gas price were higher than the CSPI, CCGT generation would be more expensive than coal-fired generation.

The month-ahead CSPI, assuming 45% efficiency, has been on an upward trajectory in May to-date, gaining from 33.84 p/th to 35.06 p/th between May 3 and May 13, clocking 34.61 p/th May 6.

The combination of bullish coal and relatively flat power prices has widened the differential between the NBP month-ahead contract and the CSPI, meaning gas has become better positioned as a fuel for power generation.

The month-ahead differential rose above its quarter-ahead equivalent in the beginning of May as June 16 became the front-month contract, the first time this year to date.

The month-ahead differential has climbed from 5.31 p/th May 6 to 6.01 p/th May 13, while the gain in the quarter-ahead differential has been more modest from 4.47 p/th to 4.92 p/th.

This suggests the improved competitiveness might prove short lived, although much depends on how coal prices develop.

While the CSPI gauges strictly the relationship between coal and gas, the clean spark spread indicates the differential between gas and power prices, an indicator that has also showed signs of strength, albeit not to the same extent as the CSPI.

The month-ahead clean spark spread assuming 45% efficiency has climbed from GBP0.90/MWh May 3 up to GBP1.67/MWh May 13.


As a result of the increased competitiveness of gas against coal allied to coal-fired plant closures, gas-for-power demand in the UK has increased by more than 50% year on year so far in 2016.

A total of 7.644 Bcm (56 million cu m/d) has been used by UK gas-fired power stations to generate electricity during the January 1-April 16 period this year, 56% higher when compared to the same period in 2015.

Moreover, cumulative gas-for-power demand so far in 2016 stood only marginally below the 7.858 Bcm used during the January 1-April 16, 2011, period, the last time gas in the UK was the dominant fuel.


Source: http://www.lngworldnews.com/

Source: http://www.platts.com/

Chilean mining powerhouse looks to new options to emerge from global mining slump


One of the world’s mining powerhouses – Chile – says the country has now adopted a proactive stance to reduce foreign investment barriers in its mining sector as it joins a plethora of mining jurisdictions worldwide battling to mitigate the resources downturn.

Addressing the first day of the two day Paydirt 2016 Latin America Downunder conference in Perth today, Chile’s Vice Minister of Mining, HE Ignacio Moreno, said Chile had not escaped the pain of the downturn but was working through options to improve performance.

“Mining exploration, as well as national and the global mining industry, is at a depressed stage,” Mr Moreno said.

“In this negative context, Chile’s national mineral exploration budget dipped 13.1% in 2015 but this was lower than the country’s overall budget decline of 18.3%,” he said.

“This budget outperformance can be seen as a sign of confidence in the ongoing mining potential in Chile – the worlds’ leading copper producer.

“On a global comparison, it also allowed Chile to move into fourth place worldwide in terms of exploration investment.

“Importantly for the longer term, while we have seen miners and explorers in Chile reduce their exploration budgets in response to the complex market periods, the upside is they have used that window of opportunity to concentrate their focus on improving the geological information surrounding their mining projects.”

Mr Moreno said the Government regarded midsize and junior minerals exploration in Chile as fundamental to the country’s continued re-emergence from the resources slump and had adopted a raft of changes to crystallise the sector’s recovery.

These included a National Geological Plan which provide for government to obtain contributing information from private explorers and miners, and to enhance basic and thematic mapping of the country’s rocks, chemical concentrations and geothermal and underground resources at different scales.

“It is essential for a well endowed minerals province like Chile to attract investment through being able to offer  much higher quality geoscience information, particularly on the formation and exploration potential of its mineral deposits,” Mr Moreno said.

“We are focused on derisking resources investment in Chile and this has seen gains in the number of companies now dual listing in Chile and on the mining renowned Toronto Stock Exchange,” he said.

“It is our long-term policy to better leverage the importance of exploration in Chile with new public-private alliances.”


Source: http://www.mining.com/

Source : http://www.mining.com/

Debunking 4 Myths About The Clean Energy Transition, Part 4: Carbon Emissions


America’s electric system is at a stark inflection point: coal power plants are operating at all-time lows with growing retirements, natural gas prices are at historical lows while power generation is rising, electricity sales are flattening, extreme weather events are forcing more resilient infrastructure, and plunging renewable energy prices have made low- or zero-carbon sources cost-competitive with conventional fuel sources.

Rapidly reducing greenhouse gas emissions from the electricity sector is now possible without radically disrupting grid operations, costs, or reliability. But the grid will require a more substantial transformation as we rely on higher shares of variable renewable generation. Some critics argue technological, financial, and institutional barriers will prevent significant decarbonization in the electricity sector, or will drive up the costs at the very least. But four common clean energy myths are easily debunked by facts and experience that show a low-carbon energy future is possible without sacrificing affordable, reliable service.

Myth #4: Natural Gas Generation Is The Main Reason For The Decrease In Carbon Emissions

Reality: Renewable energy and energy efficiency have played major roles in the decline of CO2 emissions

According to Energy Information Administration data, US carbon dioxide emissions peaked in 2007 at 2,425 million metric tons and have remained below that level in the years since.


source: http://cleantechnica.com/

Because of the coincident rise in power sector natural gas capacity, it’s easy to conclude our transition from dirty coal to less-dirty natural gas is the biggest contributor to this decline. However, significant evidence shows the acceleration of renewable energy and energy efficiency contributed far more than natural gas in reducing carbon emissions.

While more natural gas generation (215 terrawatt-hours, or TWh) has been added than non-hydro renewables (approximately 180 TWh) since 2007, renewable generation produces essentially zero emissions, while natural gas still emits roughly half the carbon dioxide that coal does. This means added renewable generation may have twice the impact of natural gas in reducing carbon dioxide emissions when it replaces coal. And that’s only factoring in the downstream emissions from natural gas combustion; when upstream methane leakage is taken into account, natural gas may be just as bad for the climate as coal. Thus, the addition of renewables has had a far greater relative impact in reducing emissions.

Energy efficiency has, perhaps, been an even greater contributor to emissions reductions than either natural gas or renewables. For decades, new appliances, equipment, and building techniques have been enhanced to consume less power while providing the same level or even improved performance. All of this has had a major impact on overall electricity use, which has decreased from 2007 to 2014.

While electricity sales did take a sizeable dip during the Great Recession in 2009 and rebounded after economic recovery in 2010, sales have since turned downward again, despite continued strong economic growth.


source: http://cleantechnica.com/

Between utility efficiency programs and tightened codes and standards, efficiency efforts have reduced electricity demand by about 200 TWh, and are estimated to have contributed at least a third, if not more, of total emissions reductions to date.

Pulling It All Together

Accurately estimating the cost of electricity sector decarbonization is undoubtedly a difficult endeavor because of rapid cost declines, myriad technologies, market operations, and other nuances. Institutional inertia favoring an outdated system further clouds this picture.

Nevertheless, it is increasingly clear that today’s available technologies and options can successfully decarbonize the electric sector. In order to cost-effectively achieve the goals many states and countries have laid out, policymakers must have the best available information, and use it to guide policymaking.

Moreover, today’s economy is extraordinarily favorable for investment in renewable resources to make the leap policymakers know is necessary to avoid catastrophic climate effects. Low natural gas prices and the proliferation of energy efficiency technologies mean that utility bills will be kept low, providing a cushion for early investment in renewable resources. The cost of money is at an historic low, encouraging renewable developers to invest. And finally, federal tax incentives for solar and wind power are at peak levels.

Avoiding these four common myths about decarbonizing the power sector can help guide analysts and policymakers toward the solutions needed to reach an affordable, reliable, clean energy future.

source: http://cleantechnica.com/

Souki-Houston venture files with FERC for Louisiana LNG export plant


Driftwood LNG has last week filed a request with the U.S. FERC to initiate the pre-filing environmental review process for its proposed LNG export facility and associated pipeline.

The company is developing an LNG production and export terminal on the west bank of the Calcasieu River, south of Lake Charles, Louisiana. Once complete, the terminal will be able to export up to twenty-six million tonnes of LNG per year, according to Driftwood LNG.

Driftwood LNG is a subsidiary of Tellurian LNG, that was formed in February this year by former CEO of Cheniere Energy, Charif Souki and former COO and executive director of BG Group, Martin Houston.

According to the documents filed with FERC, Driftwood LNG (DWLNG) plans commencing construction by the second quarter of 2018, with the first plant becoming operational in 2022. The overall project construction is expected to be complete in 2025.

The facility site will cover an area of approximately 800 acres. DWLNG said it had purchased approximately 140 acres and has leased an additional 475 acres of the facility site with the right to enter into a long-term lease for up to a total of fifty years.

In total, the project would produce up to 26 MTPA of LNG for export, requiring up to four billion cubic feet per day of feed gas. The liquefaction facility will consist of five LNG plants. Each plant is comprised of one gas pre-treatment unit and four liquefaction units, DWLNG said.


                                             source: http://www.lngworldnews.com/

The chilled fuel would be stored onsite in four storage tanks with a capacity of approximately 175,000 cbm each.

The marine loading facility, that would be located along the Calcasieu River, includes three berths for LNG ships ranging from 125,000 cbm up to 216,000 cbm cargo capacity, DWLNG said.

As per the pipeline, DWLNG intends to develop a new open access interstate pipeline to connect with multiple, existing interstate pipeline systems.

DWLNG plans to conduct an open season for the 96-mile long pipeline prior to the submission of the Section 7 application, and is currently evaluating routing for the pipeline.

DWLNG also revealed it has engaged several contractors to assist in the development of the LNG project. The contractors, among others, include Bechtel, Chart and Clough.

source: http://www.lngworldnews.com/

CEER: current LNG infrastructure in Europe sufficient


In its response to the European Commission’s LNG strategy, the Council of European Energy Regulators argues that current LNG infrastructure is sufficient to satisfy demand in most regions across Europe.

In its LNG and storage strategy, the Commission calls for the construction of priority infrastructure projects to give all member states access to LNG, either directly via terminals or indirectly via interconnectors or access to liquid hubs.

CEER, however, is calling on the Commission to “clearly differentiate whether the new infrastructure is needed under normal circumstances to supply European gas demand, or only in case of supply disruptions, for security of supply purposes.”

In CEER’s opinion, the sufficiency of current infrastructure, under normal circumstances, is demonstrated by the low level of congestion across Europe.

“Investment in interconnection and regasification capacity in recent years has facilitated gas circulation across the EU. LNG terminals have low utilisation rates across Europe currently,” the council adds.


CEER said in its response that the EC should identify precisely where bottlenecks appear when replacing missing gas sources (security of supply crisis), and to what extent they could be addressed by a better access to the LNG market.

“The investments potentially needed to alleviate possible congestion in times of supply crisis should be decided by taking into consideration their cost efficiency regarding the disrupted demand,” the council said.

CEER underlines that any new LNG project willing to receive a PCI (Projects of Common Interest) label and for which there is no market demand should be subject to a cost-benefit analysis, to weigh the additional security of supply benefits (compared to the existing situation) brought by the investment against its costs.

In order to avoid stranded costs, CEER recommends ensuring an efficient use of current infrastructure as much as possible, especially in a context of decreasing gas demand in Europe. On the other hand, when contractual congestions appear, CMP guidelines can guarantee an efficient use of the cross-border capacity.

source: http://www.lngworldnews.com/

Gold demand just had a major growth spurt


Gold demand hit its highest level ever for a first quarter in 2016, jumping to jumped to 1,289.8 tonnes or 21% more than the same period last year, according to the latest World Gold Council report

The industry body attributed the surge, which also makes the period from Jan to March January and March 2016 the second strongest quarter on record, to economic uncertainty.

Investors, says the report, sought out exchange traded funds backed by the metal amid volatility in equity markets, concerns about China and negative central bank interest rates.

Gold prices are up more than 20% year to date and rose nearly 16% in the first quarter alone. It was the strongest price performance in nearly three decades.

The rally has been almost entirely driven by investors in physical gold-backed exchange traded funds and large-scale futures speculators like hedge funds.


Source: http://www.mining.com/gold-demand-just-had-a-major-growth-spurt/

In contrast, all other demand categories fell sharply. Central bank’s slowed considerably in the first quarter, falling 3% annually and 31% from the fourth quarter.


source : http://www.mining.com/gold-demand-just-had-a-major-growth-spurt/

Physical gold demand in the two largest consumer markets of India and China remains weak, shows the study, adding that jewellery demand dropped 19% in the period.

Overall, the council anticipates that gold demand will remain healthy this year, fuelled by ongoing market uncertainty, unconventional monetary policies and an expected recovery in India.

Source: http://www.mining.com/gold-demand-just-had-a-major-growth-spurt/

Oil rises to six-month high as Goldman sees demand above output


Futures climbed 3.3% in New York. The shift to a supply deficit this month came one quarter earlier than forecast, Goldman Sachs said in a report. The bank raised its price forecasts, while projecting a return to surplus early next year. Militant attacks and pipeline outages have cut Nigerian volumes by at least 30%, its petroleum minister said last week.

“There are a lot of disruptions out there and as a result crude production is down,” said Michael Wittner, the New York-based head of oil-market research at Societe Generale SA. “Nigeria is the big one right now. There are also disruptions in Libya, Venezuela and a number of other places.”

After falling to a 12-year low in February, oil has rebounded on signs the global glut will ease amid production cuts. The supply surplus in the first half of this year is proving to be smaller than estimated, the International Energy Agency said last week, citing robust demand in India and other emerging nations. Morgan Stanley, Barclays Plc and Bank of America Corp. joined Goldman Sachs in noting that supply losses are leading markets to rebalance.


source: http://fpif.org/

Goldman Sachs

West Texas Intermediate for June delivery rose $1.51 to settle at $47.72/bbl on the New York Mercantile Exchange. It’s the highest close since Nov. 3. Prices have climbed more than 80% from this year’s low.

Brent for July settlement rose $1.14, or 2.4%, to $48.97/bbl on the London-based ICE Futures Europe exchange. The contract also closed at the highest level since Nov. 3. The global benchmark crude ended the session at a 55 cent premium to July WTI.

Fuel prices have surged with the gain in crude. Gasoline for June delivery climbed 1.1% to $1.063 a gallon, the highest close since August. June diesel advanced 2.6% to $1.4401, the highest since November.

The gain in futures bolstered equities. Commodity companies accounted for four of the seven biggest gainers on the Standard & Poor’s 500 Index. The S&P 500 Oil & Gas Exploration and Production Index climbed as much as 3.6% before closing up 2.5%.

Market Balance

“The physical rebalancing of the oil market has finally started,” Goldman analysts Damien Courvalin and Jeffrey Currie wrote in the report dated May 15. “The market has likely shifted into deficit in May.”

Goldman increased its WTI price forecasts for the second quarter through the fourth, while raising its full-year 2016 projection to $44.60/bbl from $38.40. There’ll be a more gradual decline in inventories in the second half than previously estimated and a return to a production surplus in the first quarter of 2017, with low-cost output continuing to grow, the bank said.

The global oil market will return to balance in the third quarter, Daniel Yergin, vice chairman of industry consultants IHS Inc., said on Bloomberg Television. Crude will probably trade around $50 in the second half of 2016, he said.

The oil market “looks set on a course for rebalancing much faster than previously expected,” making the risk of a sharp price drop unlikely, Barclays analysts Miswin Mahesh and Kevin Norrish said in a report. Francisco Blanch, head of commodities research at Bank of America Merrill Lynch, reiterated his forecast for U.S. prices to reach $54 in the fourth quarter as supply retreats.

“There’s optimism about the direction of the market,” Michael Lynch, president of Strategic Energy & Economic Research in Winchester, Massachusetts, said by telephone. “Between Nigeria, Libya and Canada, we’ve lost a substantial amount of output.”

Source:  http://www.worldoil.com/news/2016/5/16/oil-rises-to-six-month-high-as-goldman-sees-demand-above-output

Two-Phase Flow


Gas-liquid two-phase pipe flow is of significant importance in a wide range of engineering industries such as steam generators, chemical process plant, distillation processes and heat transfer systems. The design of these systems is often a complex phenomenon

Using suitable engineering simulation software can help the engineer design efficient and effective systems, understand plant performance and quickly evaluate alternative design scenarios.

In two-phase flow, the vapor mass fraction is often not constant and there is mass transfer between the fluid phases. FluidFlow takes this into account in your model solution. In fact, you can see the results for inlet and outlet vapor quality for all pipes and elements in your system. Flow pattern maps are generated automatically for all pipe in the system, helping you identify flow regimes and any undesirable operating conditions.

FluidFlow is used successfully by engineers to calculate pressure losses and flow distribution in two-phase pipe flow systems. The simulation software will automatically track fluid phase-state throughout the piping distribution system and the software is provided with a comprehensive database of two-phase fluids, boosters and associated piping equipment. Automatic control valve and equipment sizing is included helping you to accelerate the design process.

FluidFlow is easy to use and new users are provided with a Designer Handbook meaning you can tackle those design projects instantly.

For more information on Two-Phase Flow click here

Iron ore keeps dropping


Supply-demand fundamentals for iron ore appear to be moving back to balance amid steel supply concerns and after Chinese stock market regulators announced more steps to discourage speculative trading in the steelmaking commodity.

Both steel and iron ore prices slumped on Friday, with iron ore ended the day 5.2% lower at $55.68 per tonne, and steel rebar and hot rolled coil down a respected 4.6% and 4%. Iron ore futures on the Dalian and Shanghai exchanges was down 13% for the week, and hot rolled coil fell 12%, bringing losses since April 21 to around 25%.


Credit: http://financialtribune.com/

The two commodities have been hotly traded since the start of the year, with speculative trading fueled by Chinese steel mills increasing their output and expectation that the Chinese government will stimulate the economy, including the housing and infrastructure industries, which would require higher amounts of steel.

Mid-April iron ore hit a 16-month high of $68.70 after a double digit jump over just two trading days amid frenzied dealings in futures on the Dalian Commodities Exchange. However on Monday, news reports coming out of China reversed expectations of a sustained stimulus package, leading to widespread selling.  On Tuesday, the most active DCE contracts settled 4.7% lower at 384.50 yuan or $59.10 a tonne.

“The message from Beijing early this week suggests a slimmer chance of further easing, which hurt sentiment and triggered panic selling in steel-related commodities,” the Wall Street Journal quoted Wang Ying, an analyst at CCB Futures.

The newspaper also noted a BMI Research report that says low steel prices caused by an oversupplied market will make it tough for Chinese steel producer to remain profitable. The subsequent lesser demand for iron ore will push prices lower, says the report.

Source; http://www.mining.com/iron-ore-keeps-dropping/

EIA International Outlook to 2040 Foresees Decoupling of Power Demand and Economic Growth


The world’s frenzied economic growth through 2040 won’t be matched by electricity demand growth, the Energy Information Administration (EIA) says in the International Energy Outlook 2016 (IEO2016 ) released on May 11.

World net electricity generation will jump 69% by 2040, the IEO2016 reference case projects, but that is still well below “what it would be if economic growth and electricity demand growth maintained the same relationship they had in the recent past,” the agency’s biannual forecast says.

According to the EIA, from 2005 to 2012, world gross domestic product (GDP) increased by 3.7% per year while world net electricity generation rose by 3.2% per year. The IEO2016reference case suggests that between 2012 and 2040, while world GDP will sprout by 3.3% per year, but world net electricity generation will grow only about 1.9% per year.


World electricity generation by fuel (2012 to 2040). Source: EIA/IEO2016

The lowered demand growth projections hinge on actions that many countries may take to improve efficiency. Most members of the Organisation for Economic Co‑operation and Development (OECD) are also pursuing policies and rules that could force generators to curb their carbon dioxide emissions.

The IEO2016 reflects newly introduced clean energy policies, including China’s target to get 15% of its electricity from renewables by 2020, the European Union’s 2030 Energy Frameworkobjectives, and India’s ambitious wind and solar initiatives. It does not, however, include the effect of the August 2015–finalized Clean Power Plan (though effects of the proposed rule are considered).

A Shadow on Coal Generation, a Spotlight on Natural Gas, Renewables, Nuclear

Among its notable findings [SLIDESHOW] is that coal’s share of world generation, which has typically hovered between 37% and 40% since the 1980s, will drop from 40% in 2012 to 29% in 2040—even as world coal-fired generation increases by 25% through 2040. These echo findings by the International Energy Agency in its November 2015–released World Energy Outlook (WEO-2015), which projects that coal’s share will drop from 41% in 2013 to 30% in 2040.

And despite current low oil prices, the use of petroleum and other liquid fuels for power generation is also expected to fall. The EIA projected that oil prices will be higher in the long term, and generation from liquid fuels will fall from 5% in 2012 to 2% in 2040.

Comparatively, the IEO2016 foresees a tremendous expansion for both the shares of renewables and natural gas generation. Renewables’ share is expected to grow from 22% in 2012 to 29% in 2040—mostly from hydropower, but also substantially from nonhydropower renewables. The share of nonhydropower renewables is projected to shoot up from 5% in 2012 to 14% in 2040 in the IEO2016 reference case. In developing countries, solar’s forecast growth—at an average 15.7% per year over the period—is expected to overshadow wind’s 7.7% and geothermal’s 8.6% per year growth. In the OECD region, wind, solar, and geothermal generation is predicted to grow at comparable rates of about 4.5% per year.

Source: http://www.powermag.com/eia-international-outlook-to-2040-foresees-decoupling-of-power-demand-and-economic-growth/

US refinery capex to stay robust as owners target upgrades, quicker ROI


Despite narrower refining margins, US petroleum refinery capital spending will remain robust in the next two years, with about $9.2 billion worth of active capital projects (scheduled for construction start in 2016-2018) planned for 2016 and $9.3 billion in projects in 2017, according to market research firm Industrial Info Resources (IIR).


Photo Credit : http://www.southernstudies.org/

Some $8.1 billion worth of active projects in the US with a construction kick-off in 2016-2018 are projected to be new builds and about $1.7 billion will be unit additions, based on the pipeline of announced projects, with the rest of the spending going into plant expansions and other in-plant capital.

Future spending in the US will be mostly driven by smaller, quick-return optimization & reliability projects, facility upgrades to address octane loss issues, as well as gasoline production increases as domestic refiners take advantage of cheap domestic feedstock, comply with environmental regulations and export more petroleum products to meet rising global demand.

There are currently a total of $10 billion active refining projects under construction in North America compared to $32.5 billion in projects in the Middle East, Chris Paschall, IIR’s vice president of global research for the petroleum refining industry, said at a webinar on March 15.

By contrast, projects at the planning & engineering stage that are planned to begin construction in 2016-2018 total about $58 billion (347 projects) in North America compared to $53 billion (280 projects) in the Middle East. Though not all of this planned investment will move forward, Paschall expects to see robust spending activity in North America in 2016.

Total capital spending in the US refining and marketing sector in 2016 is projected to rise from $13.5 billion in 2015 to $14.6 billion in 2016, up 8% year on year, according to the Oil & Gas Journal (OGJ).

OGJ’s projections assume oil prices of about $35 per barrel (b) for Brent and West Texas Intermediate (WTI) in 2016.

Brent and WTI crude oil prices are expected to average $34/b in 2016 and $40/b in 2017, according to the Short-Term Energy Outlook (STEO) published by the US Energy Information Administration (EIA) on March 16.

Source: http://analysis.petchem-update.com/engineering-and-construction/us-refinery-capex-stay-robust-owners-target-upgrades-quicker-roi?utm_campaign=PTC%2024MAR16%20Newsletter.htm&utm_medium=email&utm_source=Eloqua

Compressible Flow Systems


FluidFlow customers use the software to design and optimize a wide range of compressible pipe flow systems including; natural gas transmission pipelines, steam distribution systems and compressed air systems.

For compressible fluid flow in pipes, the pressure and temperature conditions continuously change as a gas or vapor flows along a pipeline. This means that the physical properties of density, viscosity, heat capacity, thermal conductivity, velocity etc, change with pipe length.

FluidFlow uses a number of compressible flow equations, and incorporates the Joule Thomson effect to obtain a rigorous solution which is accurate for both low and high velocity flow systems.

By using FluidFlow, engineers can accurately calculate compressible flow through an orifice plate, control valve, relief device, nozzles, valves and all common piping components. You can also automatically sizing pipes, pumps, ducts, fans, compressors, control valves, relief devices (ISO & API), orifice plates and nozzles.

The software can also calculate heat loss/gain from pipes and model buried pipe heat transfer. The software is provided with a library of insulation materials as standard and engineers can select the desired insulation thickness. Convection, conduction and radiation losses are calculated. This means you can use FluidFlow to optimize energy use by selecting the economic insulation thickness.

For more information on Compressible Flow click here

FluidFlow Pressure Drop Calculator

FluidFlow is a pipe flow calculator which is used to perform fluid flow analysis in piping systems featuring heat exchangers, orifice plates, control valves, pumps, venturi flow meters and equipment items. The software is easy to use and supported by an experienced team of engineers which are always willing to lend a helping hand.

FluidFlow is a modular flow rate calculator. Available calculation modules include

  • Liquid
  • Gas
  • Two-Phase
  • Non Newtonian and Settling Slurry
  • Scripting (Dynamic Analysis)

The FluidFlow Liquid Module is a water flow calculator which allows you to define vendor equipment to a database such as pumps, control valves, pumps, venturi flow meters etc. When defining pumps, you can enter your vendor-specific pump curves to the database which will be stored for all your modeling projects. You can then model the performance of the pump in your system.

The software enables designers to complete fluid flow simulation studies in an instant and automatically size equipment, taking the pain out of your design projects.

FluidFlow is a flow calculator which allows you to understand flow measurement in your piping systems. You can input data obtained from a site pressure test to a model and understand exactly how your piping system is performing.

FluidFlow solves the continuity of mass, energy and momentum equations. You can clearly view result for flow rate, pressure, pressure loss, velocity, density, viscosity, temperature, Reynolds number and friction factor.

FluidFlow Overview

FluidFlow is primarily a maintenance release addressing reported bugs and adding new features requested by our users. It is recommended that all users upgrade to this release. We have updated our control valve calculation code to reflect the very latest Instrumentation Society America ISA-75 Guidelines, this includes choking detection for both liquids and gases.


  • Large networks containing many tee junctions now converge quicker. Note, it is still important to place the branch orientation (red dot) correctly.
  • Improvements made to equipment sizing consistency.
  • All Control Valve Equations now updated from ISA 1985 to ISA 2007 guide. For choked valves a warning is now provided. Added calculation of Cv at liquid choked flow conditions.
  • Added network data caching to improve performance of network version.
  • Added the ability to use visual elements on script forms (labels, list boxes, combo boxes, tabs, grids, etc.).


  • Open pipe exit pressure reverted back to pre 3.31 where stagnation pressure is assumed to be atmospheric.
  • Removed mouse wheel support for the input editor to prevent clashes with flowsheet occurring. Flowsheet now works better using mouse wheel.

FluidFlow v3.37

Primarily a release for Fortis, including all requested logging and database enhancements, bug fixes regarding gas reducers, and series choking.

General Release info:


  • Added the ability to automatically adjust atmospheric pressure for altitude.
    Options -> Calculation-> Global Settings.


  • Fixed an overwrite of value 101325 Pa a, for atmospheric pressure that sometimes occurred when resetting defaults.
  • Improved network convergence for multiple flow controllers.
  • New warning advising when a pump is acting as a turbine.
  • PD Pump auto-sizing bug fixed.
  • Fixed a bug which caused a program crash when changing to French language.

FluidFlow v3.33

Version 3.33 is primarily a maintenance release addressing reported bugs and adding new features requested by our users. It is recommended that all users upgrade to this release.

We have added the ability to make buried pipe heat loss calculations. To support this calculation, different pipe coatings, soil, and backfill types have been added to the Insulation database. In addition, the thermal conductivity as a function of temperature relationship for all insulation materials and soils has been improved.

For gases flowing at or near the saturation point in pipes with heat loss on, we have added an option to include condensate traps. If this option is “on”, the flow will stay in the gas phase at the saturation point and the software will report the mass of condensate to be removed. By default, this option is “off”, and so some of the gas will condense and become two-phase as it flows down the pipe. This means the vapor quality decreases along the flowpath because the condensate is not removed.


  • Added the ability to make a buried pipe calculation. Added different pipe coating, soil, and backfill types to the insulation database.
  • Added phosphine gas to physical property database.
  • Improved insulation thermal conductivity as a function of temperature relationship and added more data for insulation materials.
  • Added the ability to assume steam traps are present for a condensing gas. This option (‘Options | Calculation…’ menu item; Gas page) prevents gasflow from developing into 2-phase flow when heat loss is included.
  • Bill of Materials now subdivides pipes into schedules.
  • Added ability to model expansion loops in one component, instead of drawing out each individual expansion loop.
  • Added more calculation examples to QA tests and updated help file.


  • For Open Pipes and Open Boundaries with a resistance, the exit static pressure is now assumed to be atmospheric pressure. In earlier releases, the exit stagnation pressure was assumed to be atmospheric.
  • Restricted tee junction K values to maximum and minimum values: Max = 90 and Min = -15. This aids convergence without limiting practical values.
  • Added the ability to include Joule Thomson Coefficient in “Do Heat Loss Calculation”, via the ‘Options | Calculation…’ menu item; Gas page.

FluidFlow v3.31

With version 3.31, we have really focused on empowering you to build your models faster. We’ve implemented unique, cutting edge tools that will not only reduce the time it takes you to build your model on the flowsheet – we’ll also do the design for you!

Automatic Pipe Sizing: In addition to the economic pipe sizing feature, designers can now specify a desired pressure gradient or nominal velocity for each pipe element in the model. FluidFlow will then calculate the pipe diameter required to achieve that design constraint

Automatic Equipment Sizing: We already have auto-sizing in place for safety relief valves and burst disks to both API & ISO standards for liquid, gas, steam and two-phase flow systems. Now FluidFlow can auto-size all your key equipment items. Pumps, compressors, fans, orifice plates, nozzles, venturi tubes, pressure and flow controllers can now all be sized automatically, saving you time and effort.

Automatic Flow Balancing with Orifice Plates: Orifice plates can now be sized based on design pressure loss or flow rates. No more iteration in your design as you adjust orifice diameter to achieve your desired flowrate – FluidFlow will do it all for you.

Flowsheet Improvements: Getting your flowsheet built quicker is key to efficient modelling. So we’ve changed our directional components. No more “red dot” to define the flow direction of a controller. Just drop the pump or controller on the flowsheet and FluidFlow will work it all out for you. You can now also hold down the CTRL key when adding a template to continue adding multiples of the same template.

Reporting Upgrades You can now view your flowsheet data report from directly within FluidFlow. No need to export to excel to look at the raw data. The report has its own dialog box, so you can put it on a separate screen, or have it side by side with your flowsheet. We’ve improved the print quality of our exports too, so your .pdf exports are now crystal clear.


  • Ability to autosize the following equipment items: Pipes, Centrifugal Pumps, Compressors, Fans, PD Pumps, Pressure Reducers, Pressure Sustainers, Differential Pressure Controllers, Flow Controllers, Orifice Plates, Inline Nozzles, Venturi Tubes, Safety Relief Valves, and Bursting Disks.
  • Added 2 additional pipe sizing criteria options: Pressure Gradient and a user-entered Velocity.
  • No longer necessary to define the flow direction of pressure controllers.
  • No longer necessary to define the flow direction of flow controllers.
  • Hold down CTRL when Inserting a Template to continue insertion. Same logic applied to Paste.
  • Components Bar (‘View | Components Bar’)
  • New Data Report. Flowsheet Data/Data Report. (‘View | Flowsheet Data’)
  • Improved Print and Export Quality.
  • Integrated Joule-Thomson derivative into existing Equations of State and compressible flow calculations.
  • Added JT Coefficient, slurry volume fractions for each component (4 component and Liu models) to results table, printouts, etc.
  • Increased accuracy of calculation of Control Valve Cv and %Opening for gas systems.
  • Added 2-phase loss correlations for control valves. Not covered by ISA guide. Used Parcol method.
  • Default Folders for License, Data, Preferences, and Templates moved to “C:\Users\Public\Documents\Flite\FluidFlow” for NEW installations.

FluidFlow v3.23

  • Added Flowsheet Undo facility.
  • Added ability to plot two-phase flow pattern charts for ALL pipe inclinations.
  • Added ability to plot composite charts for boosters in parallel and series. Access via New flowsheet toolbar button.
  • Added ability to plot HGL and EGL charts.
  • Updated Pipe Sizing Data.
  • DATABASE ADDITIONS – Over 50 new fluids added, 40+ Pumps and valves + many more fluid equipment items.
  • CHANGE: Density results shown for all phase states are now static density. Previously Stagnation Density was shown.

FluidFlow v3.22 Build 6

  • The calculated K value is now an available result (in export, excel, tables, etc.) for the following elements: GenericK, Inline Filters, Cyclones, Expansion Bends, Known Resistance Exits, Bends, & Mitre Bends.
  • Buried Pipe Calculation now uses an iterative solution process, which results in a more accurate solution. Log Mean temperature is calculated more accurately.
  • Now possible to “Check for Updates” from the Help menu.
  • NPSHa now shown for auto boosters and PD pumps.
  • Improved heat transfer in two-phase flow.
  • Heat Loss from Pipes – Instead of R values (heat transfer resistances) being displayed, individual transfer coefficients (Inside Film, Pipe Wall, Insulation, Outside Film) are now displayed. This change was requested by several users.

FluidFlow v3.32

With version 3.32, we have improved our physical property predictions and have introduced the ability to model petroleum fractions from ASTM D86 or True Boiling Point Curve data.

We have improved the accuracy of our two-phase flash calculations, added pressure recovery effects and generally improved the two-phase solution algorithms.

Our pre-release Quality Assurance tests have been expanded (we now test over 700 worked examples, covering all phase states).

For slurry calculations a new deposition calculation method “Oroskar and Turian” has been added.

The flowsheet results presentation has been improved and this is also reflected in the generated reports.

We continue to work hard on our upcoming Version 4 product which is due to be released later this year.


  • Added ability to model Petroleum Fractions to the Physical Property Estimator and the property database.
  • Added pressure recovery into 2-phase flash calculations. The effect of this becomes apparent with liquids at their boiling point.
  • Added new correlation for estimating Settling Slurry Critical/Deposition Velocity. Oroskar and Turian.
  • Added ability for a pump to handle low two-phase quality mixtures at suction.
  • Improved Two-Phase flow calculations by tracking enthalpy along pipe; this allows for more accurate flash calculations.
  • Added ability to show control valve charts from the flowsheet.
  • Improved flowsheet text and fly-by formatting.
  • Added ability to activate over a network.
  • Addition of an automatic backup to the DATA folder. Occurs every 30 days by default.
  • Added more QA examples. We now have over 700 examples that are fully checked before each new release: 85 Two-Phase, 176 Compressible, 79 Equipment Sizing, 251 Incompressible, 79 Non Newtonian, 11 Petroleum Fraction, 8 Saturated gas and Two-Phase and 22 script examples.


  • Velocities and Pressure for ALL size change elements are now based on the actual size of the element.
  • Added additional checks for out of range atmospheric pressure changes made by the user via the ‘Calculation Options’ dialog.
  • Removed ability to customize the Components Palette.

FluidFlow v3.30

  • Added NEW settling slurry calculation method. 4-Component model based on a 2007 paper by Sellgren and Wilson.
  • Added NEW settling slurry calculation method. Liu Dezhong method.
  • For settling slurries, size distribution charts can now be viewed at the Supply Node(s).
  • Added the ability to Size Relief Valves and Bursting Discs to API520 or ISO4126
  • Flowsheet – Added the ability to drag an OpenPipe node to make a connection to any other node (provided node can accept another pipe connection) OR to drag an OpenPipe into an existing pipe.
  • Flowsheet – Added the ability to rotate any node, in 90° increments for ortho mode and in 30° increments for iso mode.
  • Flowsheet – Added the ability to store a flowsheet as a template. Templates can be inserted into existing networks and connected via drag connect.
  • Added a resources window, that connects back to website for examples and videos.
  • Improved the temperature and pressure range and the accuracy of the internal relationships used to predict air physical properties.
  • Expanded the pipe heat loss calculation method, to enable direct entry of U values. Full calculation of U value is also available.
  • Added Specific Heat Capacity, Flow Cross Sectional Area and Out Flow Cross Sectional Area to results table, flowsheet properties, fly-bys etc.
  • Data added for PE100 Polyethylene Pipes, Non Newtonian fluids (phosphate clays, red muds, fly ash, sugar processing fluids and various foodstuffs).
  • Created a Licence Manager that also gets installed with the software, allowing greater licence flexibility.

FluidFlow v3.22 Build 5

  • Added ability to calculate heat loss in buried pipes.
  • Improved calculation consistency for non-Newtonian Casson and Hershel Bulkley fluids.
  • Input Inspector now highlights properties that have been edited (i.e., changed from default values).
  • All calculation modules are now available for each calculation, but user has a restricted view of results if a calculation module is missing.
  • Improved gas mixture physical property prediction. You can now use mole or volume fraction to define a mixture.
  • Improved gas calculations with heat transfer. Better integration of heat transfer equations into loss calculations and improve consistency of results.
  • New warning added to slurry module if user attempts to input a solids concentration greater than the packed bed voidage.

FluidFlow v3.22 Build 4

  • Added back the ability to decide on the Vsm calculation method for settling slurries.
  • Added results to text output.
  • Expanded scripting section of the help file.
  • Added some new PP and PPF Pipes and some new PP diaphragm valves into databases.
  • Stopped an “Out of Resources” error occurring in the scripting window if margins were shown.
  • Fixed a heat transfer bug that occured when 2 exchangers were used in series, with the Heat Transfer Option set to “heat transfer into network”.
  • Fixed a bug that occured if a dialog box was shown off screen.

FluidFlow v3.22 Build 3

  • Networks can now be imported and exported via text files.
  • Added ability to size pipes automatically – Beta Release.
  • Over 50 new fluids added bringing total of fluids in the database to over 1050.
  • Settling Slurry Calculations – Method extended to included inclined pipes.
  • Added ability to run help files locally from the network release.
  • Database mixtures can now have a fixed phase state, this is useful for users who do not have the 2 phase module.

FluidFlow v3.22 Build 2

  • The V3.22 upgrade now supports Paper/Pulp Stock calculations as a standard part of the Slurry and non-Newtonian module.
  • ASME and ISO 4126 calculation methods for predicting flow across safety Relief Valves are also available across all modules.
  • This release also provides the ability to export and import network designs via text files, meaning it is now possible to interface FluidFlow to other applications.
  • The dynamic analysis and scripting module has undergone a major internal reorganisation to speed improvements and additional functionality. Users can now write scripts in Basic as well as Pascal, for instance, users can easily call Excel directly from script with methods available to set and get Excel data and charts.
  • In response to user requests, the V3.22.2 release has improved UI speeds and additional abilities such as the specification of stagnation or static pressure at boundaries.

FluidFlow v3.22 Build 2

  • The V3.22 upgrade now supports Paper/Pulp Stock calculations as a standard part of the Slurry and non-Newtonian module.
  • ASME and ISO 4126 calculation methods for predicting flow across safety Relief Valves are also available across all modules.
  • This release also provides the ability to export and import network designs via text files, meaning it is now possible to interface FluidFlow to other applications.
  • The dynamic analysis and scripting module has undergone a major internal reorganisation to speed improvements and additional functionality. Users can now write scripts in Basic as well as Pascal, for instance, users can easily call Excel directly from script with methods available to set and get Excel data and charts.
  • In response to user requests, the V3.22.2 release has improved UI speeds and additional abilities such as the specification of stagnation or static pressure at boundaries.