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GasFrac’s president sees golden opportunity in waterless fracking in Ohio

By Tom Knox

Oil and gas companies want waterless fracking because it could work better than water fracking. Residents want waterless fracking because it saves millions of gallons of water and cuts down on transportation needed to truck used water away.

Add that to a failure of Ohio’s oil and gas companies to economically drill for oil in the northern and western part of the state’s Utica shale play, and Canadian company GasFrac Energy Services Inc. sees a golden opportunity, its president told me.

GasFrac has begun testing its first waterless fracking well in Tuscarawas County, as I reported last week.

“We think there’s a lot of work in Ohio and a lot of potential there,” said GasFrac president Jason Munro.

Munro couldn’t confirm that Houston-based EnerVest subsidiary EV Energy Partners LP (NASDAQ:EVEP) is the company working with the GasFrac on the test oil well, but its executives have made public comments alluding to the partnership. It’s one of the worst-keep secrets in the industry, one which EV executive chairman John Walker said could be its most valuable asset in the Utica.

GasFrac’s technique uses gelled propane instead of water in hydraulic fracturing. Munro said the technique could work in natural gas formations, but oil is the target. Drillers have had a hard time economically drilling for oil in Ohio; the process isn’t the same for extracting natural gas.

“The oil window in Utica appears to be water sensitive,” Munro said.

Fracking creates cracks in the shale formation to make it easier to bring oil out.

In the Utica oil window, shale captures and retains water when it’s used during fracking. It swells the formation, causing a blockage for the water and oil.

Propane is a gas and can come through those cracks easier, allowing the oil to flow more easily toward the surface.

“When you frack with water, you might get 8 (percent) to 40 percent of the water back,” Munro said. “With us, when fracking with hydrocarbon, you get 70 (percent) to 100 percent of the hydrocarbon back,” so it can be reused.

Concerns about water use will only grow. A Deloitte report on the topic found that Americans pay more for water than any other utility, and “shortages stemming from increased water competition and droughts” in many areas.

Researcher IHS Inc. found up to 10 percent of total capital expenditures can be attributable to a single shale well.

GasFrac has shaken up its management team – Munro joined the company this year – and is exploring selling or merging part or all of the Calgary, Alberta, company.

It lost $61 million (Canadian) in the first nine months of its latest fiscal year on sales of $31 million (Canadian).

The company has other businesses than waterless fracking, but a lot is riding on the test well. If the Ohio well is successful, “we’re talking different options than were presented before,” he said.

If it doesn’t do well?

“I certainly think the opportunity is a big one,” Munro said, but the company has a lot of options:“In my view, this won’t be our swan song if the well doesn’t work out.”

Editor’s note: Munro’s comment in an earlier version of this story confused some readers, so we paraphrased it for clarity.

Munro said the company is “cautiously optimistic” about the test well and is in talks with other area companies for potential partnerships. It should have some preliminary results on the well soon.

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Article Source: Knox, T. (2014). GasFrac’s president sees golden opportunity in waterless fracking in Ohio. Retrieved from

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oil worker

Shale academy ready to graduate oil and gas workers

By Greta Mittereder

SALINEVILLE, Ohio (WKBN) – The Utica Shale Academy, located inside Southern Local Schools, held a special demonstration Tuesday for students and board members.

Austin Sadler, 17, is the only senior in the academy. He hasn’t wasted any time obtaining three certifications needed to get a job in the oil and gas industry after graduation.

Sadler said he has learned how to case a well, install pipe and tubing and understands how gas and oil is extracted from the ground. The first certification he received was for safety, called the Rig Pass.

“It allows me to be safely on any rig. I can be on a rig and know what I am doing and what not to do,” Sadler said.

Utica Shale Academy Director Eric Sampson said there are three certifications the students can receive. The Rig Pass, which is for safety; Drilling Instructors Training (DIT); and Well Controlled Certification.

“All of these are IDAC certified courses with the International Association of Drilling Contractors,” Sampson said.

The students have been working through modules and learning about the industry. Some of the work is done online and guest speakers are brought in to relay first-hand experiences from the field. Other work is supplemented with hands-on course material from the Ohio Oil and Gas Education Energy Program.

An advisory board will be set up to give the academy more insight into the oil and gas industry and prepare for changes in the job market.

“The advisory board is here to say here is what we have produced thus far. But as the job market evolves and different skills are needed, we want to make sure that our curriculum still matches the jobs that are available to the students,” said Chuck Kokiko, Jefferson County Educational Service Center.

Brian Logue, a representative for Express Energy, conducted a demonstration for the boards of Jefferson County EDs, which sponsors the academy, and the Southern Local Schools.

“He has set up rig tours for us. This is the third time he has come in to do a presentation to our students,” Sampson said.

Kokiko said the industry is still in the drilling stage and that will level off as gas companies reach production levels, but he says the ancillary and support jobs will be in the area indefinitely.

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Article Source: Mittereder, G. (2014). Shale academy ready to graduate oil and gas workers. Retrieved from

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Oil refinery

Moab energy company testing fracking method near Dead Horse Point, Canyonlands

By Brian Maffly

A Moab energy company is testing a novel method of fracking at its booming oil field outside Canyonlands and Dead Horse Point State Park.

The experimental extraction method — injecting oil rather than chemical-laden water underground — has shaken environmentalists already worried about the industrialization of a scenic area.

Fidelity Exploration and Production Co.’s wells on Big Flat have been among the nation’s most productive in 2012. But more recently drilled bores haven’t been yielding as much crude lately.

So last week, the company injected fluids in a well near Dead Horse Point in hopes of “stimulating” its outflow, according to Fidelity officials.

The hydrocarbon formation outside Moab, known as Paradox Basin, contains naturally occurring fissures that can be damaged by water, according to company spokesman Tim Rasmussen.

“We needed to find a fluid that would not damage the reservoir while at the same time being environmentally benign,” he said.

With fracking, fluids are pumped under extreme pressure into sandstone formations to force fissures that allow trapped oil and gas to flow into the well bore. The technique is credited with spurring a boom in domestic oil and natural gas production and subsequently declining prices.

But the process is fraught with controversy. Critics say fracking is not adequately regulated as companies inject vast amounts of chemical-laden fluids that could contaminate groundwater.

Fidelity’s engineers settled on a 2,200-barrel mixture of crude from the well itself and food-grade oil — a far smaller volume than is usually used in a water-based fracking operation.

Still, environmentalists say public land managers should study the impact of oil fracking before the company goes any further.

Local activist Bill Love is concerned fracking fluids could escape the well bore and migrate toward the two major rivers that pass through the area’s two national parks and two national recreation areas and provide water for millions.

“BLM has not done a study. The National Park Service needs to have a study,” said Love, who co-founded the Canyon Country Coalition for Pipeline Safety.

Drilling started on Big Flat in the early 1960s, but it wasn’t until Fidelity took over the Cane Creek unit in the late 2000s that wells there became a commercial success — without the help of a single fracking system or even a pump jack in many cases.

Rasmussen said past operators have fracked the Paradox formation, but without success.

Fidelity’s newly fracked well was completed last spring. Monthly production started with 4,144 barrels in April and steeply tapered to 1,165 barrels by September, according to state records.

The well descends 7,500 vertical feet into the oil reservoir then bends 90 degrees and travels laterally in a northeasterly direction for another 5,000 feet through the reservoir.

Fidelity injected the oil only in the toe of that horizontal leg, the half farthest from the vertical bore.

The well will remain shut in while it stabilizes, then it will be “flowed back.”

“Initial flow-back rates will be controlled and monitored,” Rasmussen said. “These rates will be compared to production before the treatment to determine the effectiveness of the experimental design.”

If production improves, Fidelity may try the technique elsewhere on Big Flat.

“We do not believe that the Big Flat wells are good candidates for traditional massive fracture treatments,” Rasmussen said. “The purpose of this stimulation is different and, if successful, could result in better recovery from our existing wells.”

Fracking with water would leave a much larger footprint than what Fidelity is pursuing, the company maintains. It takes at least 1 million gallons of water, often loaded with diesel, methanol, surfactants, gelling agents and other chemicals, to frack a well.

Water is scarce in Grand County and places to dispose of spent fracking water are even scarcer.

Rasmussen said the frack oil can be recovered and sold, therefore the operation won’t deplete local water supplies nor pose a disposal burden.

But local environmentalists remain concerned about the lack of an environmental analysis of the operation and the possibility of fracking fluids fouling groundwater.

Most of the 100-square-mile oil field is on federal land checkerboarded with state sections. The fracked well, known as Cane Creek 32-1, is on state land and could be fracked without Bureau of Land Management approval.

The state Division of Oil, Gas and Mining reviewed Fidelity’s plan and signed off on it, agency spokesman Jim Stringer said.

Wells are fracked daily elsewhere in Utah. But Big Flat is different. It’s located at the doorstep of cherished pristine lands, including Canyonlands’ Island in the Sky, on a plateau 2,000 feet above the Colorado and Green rivers.

Moab activist Love notes two “beautiful” springs are in the area — one in Hell Roaring Canyon and another outside Upheaval Dome.

“They have not taken baseline samples from the springs,” Love said.

Love’s group already is grappling with Fidelity over a network of pipelines the BLM has approved to move copious volumes of natural gas that come up with the oil and are flared at the wellheads.

At least 18 wells are producing oil on Big Flat and Fidelity drills non-stop there. BLM predicts another 50 wells are on the way.

Fidelity’s parent, MDU Resources Group, recently announced plans to sell the company that has been spending heavily on Big Flat. Despite a $150 million investment this year, daily production has inched up just 5 percent to 2,400 barrels, according to its most recent financial disclosure to investors.

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Article Source: Maffly, B. (2014). Moab energy company testing fracking method near Dead Horse Point, Canyonlands. Salt Lake Tribune. Retrieved from

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EV Energy Partners wants to sell off Utica assets in January

By Bob Downing

Texas-based EV Energy Partners is preparing to sell off its Utica shale assets in eastern Ohio in 2015, along with its interest in processing facilities.

There has been “enough drilling activity and consistent result to de-risk our assets and acreage,” said John Walker, the company’s executive chairman.

The value of the company’s Utica shale leases have grown significantly, he said in an earnings call with analysts and the media earlier this week.

The company intends to kick off a serious sale effort in January to sell off its joint venture acreage with Chesapeake Energy and Total SA in 10 Ohio counties, plus other leases held by the company, he said.

The company wants to sell about 120,000 acres within the 660,000-acre joint venture. That includes about 55,000 acres in Carroll County.

It also intends to seek a buyer for its 21 percent interest in Utica East Ohio that operates natural gas processing plants in Columbiana and Carroll counties and a liquids-separating plant in Harrison County.

Last month, EV Energy Partners sold its 9 percent interest in Ohio’s Cardinal Gas Services to two South Korean companies for $162 million.

EV Energy Partners, a publicly traded company that is part of privately held EnerVest Ltd., has said for some time that it intends to sell off Utica assets to monetize the holdings for its institutional investors. The company has been marketing about 335,000 acres in Ohio since 2013.

The EnerVest companies are one of Ohio’s largest oil and gas companies with 8,700 vertical wells in Ohio. They were the largest producer from traditional gas and oil wells in Ohio and generated 25 percent of Ohio’s natural gas prior to the Utica shale boom. They control about 900,000 acres in Ohio.

In other news, EV Energy Partners said production could begin in December on a much-watched Utica oil well in Tuscarawas County.

The company drilled the experimental well with eight other industry partners, Walker said.

“This is a test of what could be EnerVest and EVEP’s most valuable asset in the Utica,” he said.

Getting oil from the Utica shale has proven to be difficult for drillers, to date.

That well near Uhrichsville is being hydraulically fractured or fracked with liquid butane and mineral oil. That should be completed in two weeks.

“We’re excited but cautious as we are bringing new technology to bear in this process,” said company president and CEO Mark Houser. “We are in the middle of the completion operations and have completed five of the 20 (fracking) stages so far.”

A full review of the well will be offered in the next few months, he said.

The oil window covers all or parts of Portage, Stark, Trumbull, Tuscarawas, Holmes, Coshocton, Guernsey, Muskingum, Perry, Morgan, Athens, Vinton and Hocking counties.

EV Energy Partners is also getting about 80 barrels of oil per day plus natural gas from four Stark County horizontal wells that were drilled into the shallow Clinton sandstone. A fifth well is not yet in production.

Drilling each well costs about $2.6 million. Each well is projected to produce about 150,000 barrels of oil equivalents. The wells could generate 20 percent return on its investment at $80 per barrel for crude oil.

The company said the East Canton oil field where more than 4,000 wells have been drilled since 1947 has an estimated 1.5 billion barrels of oil and only 7 percent has been recovered.

The field in Stark, Carroll and Tuscarawas counties covers about 214,000 acres and EnerVest companies control half of it, the company said.

It says it has identified 70 potential drilling sites and that number could grow if the wells are successful, Houser said.

The company is “very pleased” with the initial Clinton results, he said.

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Article Source: Downing, B. (2014). EV Energy Partners wants to sell off Utica assets in January. Retrieved from

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U.S. Drillers Shift Oil Rigs to Tap Most Reliable Fields

By Lynn Doan

U.S. oil drillers put rigs back to work this week, lifting the number in operation from a three-month low in a push to home in on their most profitable fields after crude prices sank to the lowest since 2010.

Rigs targeting oil jumped by 10 to 1,578 after sliding to the lowest level since August last week, Baker Hughes Inc. (BHI) said on its website today. Those drilling for natural gas declined by six, the Houston-based field services company’s website. While oil rigs fell in Texas’s Eagle Ford formation and the Cana Woodford of Oklahoma, they picked up in the Utica in the eastern U.S. and the Permian Basin of Texas and New Mexico.

“The Permian is a tried and tested formula,” Matthew Jurecky, head of oil and gas research for the London-based research company GlobalData Ltd., said by telephone from New York. “The stuff that’d be more at risk is in the periphery, the immature plays. In the Permian, you’ve still got tons of acreage that you can drill for days and make money at $30 oil.”

The oil-rig count has fallen from a peak of 1,609 on Oct. 10 as companies slow drilling in response to a 26 percent slide in crude prices over the past four months. Hess Corp. (HES), one of the largest operators in North Dakota’s prolific Bakken shale formation, said this week that it plans to idle three rigs next year. The slump threatens to curb a production boom in U.S. shale fields that has helped bring gasoline prices at the pump below $3 a gallon for the first time since 2010 and shrink the nation’s dependence on imports.

Down 30

Declines aren’t “going to be consistent every week,” James Williams, president of energy consulting company WTRG Economics, said today by telephone from London, Arkansas. “We’re still down 30 rigs. I still think we’re going to be near 1,500 by the end of the year.”

U.S. benchmark West Texas Intermediate crude for December delivery rose $1.61 to settle at $75.82 a barrel on the New York Mercantile Exchange. Prices are down 19 percent in the past year and capped the longest run of weekly declines in almost three decades.

This week Hess joined the growing pool of drillers, including Apache Corp. (APA) and Continental Resources Inc. (CLR), who’ve said they plan to run fewer rigs in some oil plays. The New York-based company will cut its count to 14 next year “in direct response to the lower oil prices,” Geurt Schoonman, vice present of the New York-based company’s Bakken division, told investors in a conference call Nov. 10.

Domestic Output

Domestic oil output climbed 92,000 barrels a day in the week ended Nov. 7 to 9.06 million, Energy Information Administration data show. While rigs have dropped, their productivity has surged to record levels across all major oil fields, the agency said in a report Nov. 10. New crude output per rig will rise to a record 543 barrels a day in the Bakken in December and to 550 in the Eagle Ford, the report shows.

Rigs in North Dakota may fall below 180, down from 191 last month, as oil and gas operators stop renewing contracts on their least-efficient equipment, Lynn Helms, director of the state’s Mineral Resources Department, said in a conference call today.

Murphy Oil Corp. (MUR), an El Dorado, Arkansas-based oil and gas producer, said in a presentation today that the Eagle Ford is the most expensive of its major oil plays. Supply costs totaled $43.40 a barrel in the South Texas field in September, compared with $29.48 in Canadian offshore operations, the report shows.

U.S. gas stockpiles increased 40 billion cubic feet last week to 3.611 trillion, according to the EIA. Supplies were 6.2 percent below the five-year average and 5.7 percent under year-earlier inventories.

Natural gas for December delivery gained 4.3 cents to $4.02 per million British thermal units on the Nymex, up 12 percent in the past year.

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Article Source: Doan, L. (2014). U.S. drillers shift oil rigs to tap most reliable fields. Bloomberg. Retrieved from

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BP to deploy new robotic EOR technology on North Sea’s Clair Ridge

By Rita Brown

BP confirmed it is now operating the world’s first robotic coreflooding system in a bid to boost its enhanced oil recovery abilities.

The firm also confirmed the new technology will now be fully deployed on its Clair Ridge project in the North Sea.

The £4.5billion field is the first large scale enhanced oil recovery scheme. It’s expected to produce up to 120,000 barrels of oil a day, with a total estimate of 640 million over its 40-year lifespan.

Coreflooding, which measures the effectiveness of water and gas injected into oil-bearing rocks, is also used to assess the potential for flooding in an oil field.

The new robotic outfit will boost BP’s testing capabilities from a few dozen a year to hundreds. The robotic system can operate seven days a week, 24 hours a day.

Ahmed Hashmi, BP’s head of upstream technology, said: “The EOR technologies being developed by BP are vitally important to help increase global oil supplies.

“We believe this step-change in our coreflooding capability will hugely improve the speed and efficiency with which we can deploy new technologies to recover more oil from reservoirs.”

Through freeing up evaluation resources, it’s also thought the new robotic system will cut the development time allocated to new technology by more than 50%.

Earlier this year, BP was awarded the Offshore Technology Conference Distinguished Achievement Award for the Clair Ridge LoSal EOR project, recognising the company’s specialist EOR technologies.

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Article Source: Brown, R. (2014). BP to deploy new robotic EOR technology on North Sea’s Clair Ridge. Retrieved from

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Oil refinery

Oil and Gas Production: Digitizing Oil Fields

By Brian Sallery

Previously I delved into digital communication standards now commonly used within the oil industry and the importance of sharing real-time operational data between data centres and contractors.

There is also a strong move towards a completely digital virtual oil well operated and controlled by a minimum of workers, but why are companies spending millions to develop and integrate these virtual systems?

Oil prices consistently rise year on year, even when the stock markets crash, oil is always one of the first commodities to recover its costs. However the industry has always faced a shortage of skilled workers for the many areas of hydrocarbon production. It has been estimated that over 100 million barrels oil will be needed everyday by 2015 and with this amount of supply required many more engineers, geologists and rig workers will be needed. In many African countries experts are used due a lack of skilled local workers, therefore the idea of a digital oil field turns from the realms of fantasy, to now becoming reality. So what is meant by the term digital oil field (DOF)?

Software is now available to capture the daily operations and behaviours of an oil rig and can be used to manage the whole production lifecycle.  Such software should allow for a full visualisation of the reservoir and the wellbore. This enables managers and engineers to see real-time monitoring and control data offsite, real-time drilling data which should include down-hole pressures, drill directions and rotational speeds.

Furthermore Real-time surveillance will trigger alarms when production integrity has been breached. This allows companies to fully audit operations and procedures. Booz&Co reported that one company had introduced selected oil field technologies and has saved a massive US$20 million annually by automating data storage facilities, data integration across multiple systems and wellbore visualisation by using fewer but more skilled staff, located at a central control centre.

If such savings can be made why are the technologies not being taken up by every petroleum operator? Many smaller organisations are simply unable to absorb the initial implementation costs or have the forethought to properly use the available software.

Often when a new system is required it causes a ripple effect over the current system while it is being integrated into working practices. From my experience managers often struggle with new technologies, both with their effectiveness and implementation.

Furthermore workers at the ‘coalface’ can be resistant to change asking questions like ‘I have done it this way for years why should I change now?’ and this can be a major drawback to the implementation of a virtual digital system.

The whole point for a digital oil field is to help tackle some of the following areas: Supporting staff development allowing for functional specialisation of assets and operations. Supplementing an ageing workforce where oil workers with years of experience are able to move into a less physical role as they age but still utilises their immense knowledge.

Modern oil fields have a large amount of data to process with sensors being placed on almost every piece of equipment and a digital oil field brings with it the advantages of visualisation software. Also the risks and uncertainties are reduced if not eradicated due to the use of workflows and risk prediction algorithms. The problems of a lack of skilled workers are also eased as computer integration usually allows one person to do the work of many.

Finally information and knowledge is easily exchanged with organisation that have different specialism, tasks and agendas which may be very different from the main oil production skill set of the operator.

However there are issues to consider as with any new technology one must first decide on what aspect to digitise. With so much data and information to be processed a company can be quite literally overloaded and as a result paralyse a company’s decision making processes instead of helping them be more proactive with decisions.

Therefore it becomes necessary to carefully select or ‘cheery-pick’ the data required for specific information goals. The problem is if you record all available data then storage costs become prohibitive and the times required to process and sift through to find something relevant increases with every upload.

Alternatively by only selecting certain types of data, you risk deleting information that might have intrinsic value to the company. So good visualisations are vital, which allows complex data to be shown in a graphical format to simplify the decision making process.

Oil rigs produce huge amounts of data on a daily basis, so it is not about implementing digital technologies but how oil companies use it to communicate the right information to the right people in the field. The Chevron Machinery Support Centre (MSC) looks at real-time data distributed over 6 continents from Kazakhstan to Colombia they monitor 65% of the U.S gas supplies. At their hub computer operators, overview a number of computer monitors looking for distribution paths to meet current gas supplies and to check for system alerts. Recently one of their African drilling operations started to overload.

An alarm immediately alerted the controllers of a compressor problem at MSC some 6000 miles away from the original incident; this allowed the fault to be found and resolved quickly without any injuries to the workforce and saved millions of dollars in possible production downtime.

Chevron has now implemented a number of digital systems to its upstream operations one of which is called Upstream Workflow Transformation (UWT) which has taken decades of investment and development to produce, but is now at the forefront of its digital campaign.

As a way of combining IT, automation and instrumentation technologies DOF software offers many benefits from faster reservoir production and analysis, increased workforce safety and operational management through the use of workflows, as long as data is properly analysed and filtered to give expected results for manager and engineers to make timely and accurate decision.

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Article Source: Sallery, B. (2014). Oil and Gas Production: Digitizing Oil Fields. East African Business Week. Retrieved from

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Oil companies tap virtual technology to train workers

By Kyle Rothenberg

Oil companies are starting to train their oil rig workers in a virtual world — literally.

Instead of employees learning from PowerPoint presentations during training class, some companies are beginning to roll out training programs where employees get to play custom-made video games teaching them safety, rules, and procedures out on an oil rig.

The training could ultimately save their lives because working on an oil rig can be a dangerous job.

The 2013 fatality rate in the oil and gas extraction industry was 3.2 deaths per 100,000 workers according to the Bureau of Labor Statistics. That is about eight times higher than the average fatality rate in all other U.S. industries.

“When you have workers who have never been on an offshore platform, they don’t know what to expect,” said Skyra Rideaux, spokesperson for Louisiana Immersive Technologies Enterprise (LITE) — a company that creates virtual reality gaming software. “We create a virtual environment for them where they actually get to see what a rig looks like and what they’ll be doing,” she added.

Frank’s International — an industry leader in casing, installing and distributing oilfield tubulars — is experimenting with virtual reality training and hired LITE to develop software programs that recreate teachable situations on oil rigs.

Even though Frank’s International is not a part of the oil and gas extraction industry, there are still dangers when working with heavy machinery and virtual reality training can help, according to the company’s communication director Josh Grodin.

Training employees using video games and virtual reality experiences is a more efficient way of learning because it creates a more “hands on” approach that sparks engagement in the classroom, according to Jacke West, training director at Frank’s International.

LITE released a couple of virtual training exercises for Frank’s International just a few weeks ago — taking about six months to create the software. But the next video game exercises currently under production for Frank’s will not take as long, and should be completed in about a year or so, according to Rideaux.

“We learn by experiencing,” said Erin Marietta, LITE’s chief operating officer. “Everyone learns in an environment where you can touch and feel. And that’s what virtual reality does. It’s getting cheaper and a lot easier to produce,” she added.

The program costs $60,000 to $80,000 to develop, and it’s like playing a “Call of Duty” first-person video game, according to Rideaux.

West said the old-school ways of using PowerPoint presentations in the classroom are a thing of the past.

“Virtual reality training is the future,” he explained. “And our budget has been approved to expand the training in 2015.”

Part of the expansion West refers to will give oil rig trainees at his company the opportunity to use the Oculus Rift — a 3D virtual reality device created by Oculus VR, which was bought by Facebook for $2 billion earlier this year.

Oculus Rift is a head-mounted display that creates a fully immersive video gaming experience. Right now the device is only available as a development kit for software creators, but it’s expected to become commercially available in April 2015.

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Article Source: Rothenberg, Kyle. (2014). Oil companies tap virtual technology to train workers. Fox News. Retrieved from

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New app developed to help workers in the Eagle Ford Shale

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By James Aldridge

San Antonio lawyer and entrepreneur Marco Flores has launched a new Eagle Ford Mobile Network App that companies can use to tap into business opportunities in the Eagle Ford Shale.

The app is free to download and it is designed to give South Texas residents, businesses and workers in the region access to pertinent information, such as GPS-based directory information, job listings, equipment sales, industry news and the ability to search whether a person has a valid Commercial Driver’s License.

Some of the directory information accessible to rural smartphone users include contact information on oil field service providers, food catering companies, lodging, organizations that help small businesses and advocate for safety. Workers out in the field will be able to use the app to track places to eat and sleep.

“It’s going to totally disrupt the traditional ways people have historically accessed some of the basic information they need out in the field, in a good way,” Flores said in a news release. “It’s going to save businesses invaluable time and money.”

The app is available for download on Google Play and the Apple iTunes App stores. More information is available at

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Article Source: Aldridge, J. (2014). New app developed to help workers in the Eagle Ford Shale. Retrieved from

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Oil refinery

Islamic State Loses Its Oil Business

By Matthew Philips

It’s been a month since President Obama announced that the U.S. would engage in a sustained campaign of airstrikes against Islamic State, the militant Sunni rebellion in Syria and Iraq. The idea was to bomb Islamic State into nonexistence, which has proved difficult. Not only is the movement well-armed, battle-hardened, and deeply entrenched in much of Syria and northern Iraq, it’s also very well-financed, thanks to oil wells and refineries it’s been able to capture. By late June, Islamic State was raising as much as $2 million a day refining and smuggling oil, making it one of history’s wealthiest terrorist groups.

Though the airstrikes have failed to keep Islamic State from advancing in the field, they have apparently succeeded in dismantling its sophisticated oil network, reducing the movement’s ability to make gasoline and diesel for its tanks and trucks and cutting off a vital source of funding. A report from the International Energy Agency in Paris has just estimated that Islamic State controls only about 20,000 barrels of daily oil production, down from about 70,000 as of August. Most of it remains in Iraq.

In early August, Islamic State controlled sections of Syria and Iraq that together are about the size of Wyoming. At that point, its territory included seven oil fields and a refinery in northern Iraq, as well as six of the 10 oil fields in eastern Syria. Although the movement was able to produce only about half the potential output under its control, it had no problem tapping the region’s well-established oil smuggling network.

Most of the group’s oil flows through local middlemen and is paid for almost entirely in cash, making transactions extremely difficult to track and shut down. This has insulated Islamic State from traditional methods the West has used to dry up terrorist funds in the past, such as international banking sanctions and anti-money laundering laws.

A straight-up bombing campaign does seem to be doing a lot of that work. According to the IEA report, U.S.-led sorties over northern Iraq and Syria are “frustrating the jihadists’ ability to operate oil fields and refineries.” At its peak, most of the oil smuggled from Iraq was loaded from the Ajeel oil field near Tikrit on tanker trucks and routed toward Kurdistan. The IEA, citing Iraqi oil industry sources, estimates that Islamic State was loading about 120 tanker trucks with about 20,000 barrels a day from Ajeel. Sustained airstrikes, including ones targeting convoys, have cut that traffic to about 10 trucks a day, or about 2,000 barrels, according to the IEA’s report.

In Syria, the IEA estimates that Islamic State’s oil output is down to about 10,000 barrels a day. Airstrikes by the U.S., the Saudis, and the UAE have wiped out “dozens of teapot refineries” in Syria, depriving the movement’s war machine of a key source of gasoline. Turkey and the Kurds have also cracked down on its smuggling operation. In late September, the Kurds reportedly seized four militant tanker trucks from the Ajeel field and detained the drivers.

There is still a lot of work to do. The Islamists retain control of Syria’s largest oil field, the Omar field in the Deir Az-Zour region of the country. The squeeze on finances has made Islamic State even more desperate to control oil fields and refineries. Its fighters have turned Iraq’s largest refinery into a battleground–forcing it off-line and sharply reducing output. With most of its refining capacity in Syria destroyed, Islamic State might go after two big refineries, closer to Lebanon in the west of Syria, that are under the Assad government’s control, opening up a much broader two-front war and potentially limiting the movement’s ability to wage war to the east, in Iraq.

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Article Source: Philips, M. (2014). Islamic state loses its oil business. Assyrian International News Agency. Retrieved from

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GARTMAN: We’re Witnessing The End Of The Oil Era

Dennis Gartman has a new forecast for oil: a lot lower.

In an appearance on CNBC’s Fast Money on Monday, Gartman, publisher of the Gartman Newsletter, said that crude oil prices will fall demonstrably from current levels.

Earlier on Monday, it had been reported that Gartman saw crude oil going to $10 a barrel, but he backed a bit off that claim in his appearance on Monday, saying that maybe next time he ought to be a bit more circumspect when he talks to CNBC’s producers.

But the central spirit of Gartman’s not quite $10 call was still intact, with Gartman saying simply that the era of oil is over. At one point, Gartman went so far as to compare crude oil to whale oil, which became obsolete following the advent of crude in the early 20th century.  

In discussing the “end of oil,” Gartman referenced news from Lockheed Martin earlier this month that the aerospace giant has made a technological breakthrough in developing a power source based on nuclear fusion. And while Business Insider’s Jessica Orwig reported that some in the scientific community are skeptical of this breakthrough, Gartman sees the potential in this breakthrough as being something of a death knell for oil. 

Gartman also referenced other factors weighing on oil prices, namely a supply glut and a market that is contango.

A market is said to be in contango when the futures contract for a commodity is more than what the expected price will be in the future.

So basically, if I pay $80 for a futures contract for a barrel of oil I want to get next year, but if expectations are that the spot price of a barrel of oil will be $60 in a year, the futures contract — again, assuming the spot price doesn’t move — will have to fall.

This is all a bit oversimplified. 

But Gartman’s central point is that things look absolutely terrible for crude oil, and while Gartman was reticent to commit to his $10 a barrel call, he added that “it doesn’t really matter” where oil prices go exactly, except that they are definitely going lower.

Gartman’s comments come after what was an ugly morning for oil, which fell below $80 a barrel for the first time since June 2012.

The tumble in oil came after analysts at Goldman Sachs cut their price target on WTI crude oil to $70 by the second quarter of next year.

In his note, Goldman Sachs analyst Jeff Currie wrote:

“We are lowering our oil price forecast to reflect the required slowdown in US production growth: our WTI crude oil forecast is $75/bbl for 1Q15 and 2H15 (from $90/bbl previously). Given our unchanged WTI-Brent spread forecast of $10/bbl, our Brent forecast is now $85/bbl ($100/bbl previously)… Our 2016 and long-term forecasts are now $80/bbl WTI, $90/bbl Brent. Uncertainty around the required price to slow down US shale production growth is a key risk to our price forecast.”

After Monday’s early sell off, oil futures were trading just below $81 a barrel near 5:30 p.m. ET.

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Article Source: Gartman, D. (2014). GARTMAN: We’re witnessing the end of the oil era. Business Insider. Retrieved from

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Shale Boom Shines Light on Natural-Gas Liquids

By Nicole Friedman

An unsung byproduct of oil and natural-gas production is getting more attention from hedge funds and investors as they seek new ways to bet on the U.S. shale boom.

Natural-gas liquids, which include ethane, propane, butane, isobutane and natural gasoline, are separated out from crude oil and natural gas. They are known as the fuels in propane grills and butane lighters and as feedstocks to make plastics and chemicals. Until recently, they attracted little investor consideration.

But that has begun to change amid a swift increase in both supply and demand. U.S. production of NGLs topped 3 million barrels a day this year. Production volume has grown 60% in the past decade to become on par with the amount of oil produced in Texas or Iraq. Petrochemical manufacturers world-wide are expanding to take advantage of the new supply.

Investors can act as middlemen between producers and consumers of NGLs, particularly as banks are backing away from commodities trading. They also are more easily able to make bets on prices as trading volumes grow. Many investors are using NGLs as a way to bet on the North American energy boom while sidestepping the pipeline bottlenecks and export restrictions that have held down most U.S. energy prices.

It helps that unlike oil and natural gas, NGLs can easily be exported overseas, where prices are higher. Connections to the global market make it less likely NGLs will meet the same fate as natural gas, which saw prices crash when production swamped U.S. demand. NGLs fetch an average of $9.94 a million British thermal units, more than double the price of natural gas.

“Anyone you can think of in the energy space is there,” said Greg Bower, a broker at Blue Ocean Brokerage. “There’s new people in it all the time.”

Still, the drop in oil and natural-gas prices over the past few months has taken its toll, with the price of propane futures recently hitting a 14-month low on the New York Mercantile Exchange. Even so, that market has more than tripled in size since the start of May to a record $2.8 billion.

At least two new hedge funds are focused on trading NGLs, people familiar with the matter say. KC Alpha Fund I launched in January with $850,000 and a plan to focus on trading NGLs, along with other energy products, according to people familiar with the fund.

Norman MacDonald, portfolio manager at Invesco Ltd. , owns shares in oil-and-gas producers that generate a large amount of NGLs, including Range Resources Corp.

“I don’t think the market really truly appreciates just what [NGLs] can do” for oil-and-gas producers, added Mr. MacDonald, who manages the $1.4 billion Invesco Energy Fund.

NGL trading is still sparser and less transparent than in the vast markets for crude oil or natural gas. However, growing volumes are making it easier to get in and out of positions in the market, building NGLs’ appeal to large investors. Futures trading volumes in these markets rose 18% in the first six months of 2014 compared with the same period last year, according to Intercontinental Exchange Inc.

“You’re seeing global macro hedge funds step in,” said Sid Perkins, managing partner at Houston brokerage Ion Energy Group, which is owned by OTC Global Holdings. “They’ve been watching it for the last few years, and were waiting until the market got to a point where it was liquid enough for them to come in and trade.”

Another problem for traders is that NGL markets are typically not that volatile, so there are fewer opportunities to profit from price moves. Propane, the largest NGL market, saw prices spike in February as high demand from farmers, home-heating and overseas buyers all stretched supplies during a frigid winter. But stockpiles rebuilt rapidly this summer, reducing expectations for a similar squeeze this year.

The lack of transparency in the market is keeping OppenheimerFunds Inc. from trading NGLs, said George Zivic, portfolio manager for the $420 million Oppenheimer Commodity Strategy Total Return Fund.

“Unless you’re privy to what [producers and manufacturers] are doing on a month-to-month basis, you can really get squeezed,” Mr. Zivic said.

Others see potential for prices to rise, potentially drawing in more investors. Enterprise Products Partners LP plans to build a terminal by the third quarter of 2016 to export up to 240,000 barrels a day of ethane from the Gulf Coast. When Enterprise opened a propane export facility in 2013, trading volume expanded as traders prepared for greater access to overseas markets, said Michael Angell, markets editor for the Oil Price Information Service, which tracks spot NGL prices.

“I’m actually beginning to move some of my businesses more into the NGL side because of the demand,” said Steve Reese, chief executive of Reese Energy Consulting and Reese Energy Training in Edmond, Okla., who said he is planning to start a propane business. “The trading activity has definitely increased.”

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Article Source; Friedman, N. (2014). Shale Boom Shines Light on Natural-Gas Liquids. The Wallstreet Journal. Retrieved from

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