With major publications like the New York Times constantly printing horrible things about the dangers of hydraulic fracturing and the overinflated potential of shale plays, it’s not surprising that people who inhabit land atop the Marcellus shale are a little confused.

Yes, the job creation is great for small towns that have long relied on coal mining for their sustenance. But is it worth the pollution of the town’s water supply?

A few towns in West Virginia are being given a crash course in shale drilling after the state failed to agree on new rules regulating Marcellus drilling, according to an article on fuelfix.com. Deciding to take matters into its own hands, the city of New Martinsville banned Marcellus shale gas drilling. City council members were surprised by the response, and a month after the initial vote, they began rescinding the ordinance.

“I didn’t expect the pushback,” Mayor Lucille Blum was quoted as saying. “I don’t think the council did, either.”

The “pushback” included industry workers crowding a city council meeting, the West Virginia Independent Oil & Gas Association threatening to “take its business elsewhere,” and a letter from Chesapeake Appalachia suggesting that council members reconsider their actions.

Chesapeake was tougher on the city of Wellsburg. The company rescinded its US $30,000 offer to supply band instruments for the town’s middle school after drilling was banned in May.

“As a publicly traded company with many stakeholders, we must direct our expenses and philanthropy to communities that will work with us, not against us,” spokeswoman Stacey Brodak said in a statement. “We do not have to choose between the environment or the economics. We are benefiting both.”

Businessman Matt Quinet agreed, at least with the latter. Business at his restaurant in New Martinsville tripled, according to fuelfix, and he’s opened a motel in a nearby city that’s booked every night.
“These gas people have brought new life to this town,” he told fuelfix. “For any town that comes into this, it’s like the town hit the jackpot.”

This is an interesting peek into the grassroots economics of the shale boom. When states legislate against drilling or fracturing, the education process has to happen in the offices of the legislators. But when it’s left to the small towns to decide, it seems they’re more likely to listen to reason when the industry comes calling.

My job is to write about exploration technology. I think there may be an implication in there somewhere that this refers to oil and gas exploration technology, but once in awhile it’s fun to see what else is out there.

Apparently the Lunar and Planetary Institute doesn’t make this distinction either because I’ve been invited to not only attend but submit a paper for a February 2012 workshop titled “Early Solar System Impact Bombardment II.” (Unfortunately I had to miss the first one.) I can tell you right now that I won’t be submitting an abstract, but it might be fun to go.

It seems that folks who study the Moon are theorizing, based on information from the Apollo program, that the Moon underwent “late heavy bombardment” or some sort of lunar catastrophe that changed the surface and “thermally metamorphosed” its crust. “Several recent studies have continued to test that concept and explore the implications any bombardment may have for our understanding of lunar evolution,” the announcement states. “It has also been posited to be a factor in the origin and early evolution of life on Earth.”

It goes on to say that the bombardment may be linked to “a dramatic reorganization of planetary orbits.”

This is important science in the space exploration community. A National Research Council report titled “The Scientific Context for Exploration of the Moon” names a test of the cataclysm theory as a top priority for lunar studies. And results from NASA’s Lunar Reconnaissance Orbiter (LRO) resulted in three separate articles in a recent issue of Science.

One of these papers, by James Head of Brown University, said that many planets and moons closer to the sun exhibit crater scars but that those on Earth heal faster due to wind and water erosion as well as plate tectonics. But those types of impacts could have caused disruptions to the early formation of life.

“The Moon is thus analogous to a Rosetta stone for understanding the bombardment history of the Earth,” wrote Head. “… the lunar record can be used to translate the ‘hieroglyphics’ of the poorly preserved impact record on Earth.”

Head’s team used the LRO’s Lunar Orbiter Laser Altimeter (LOLA) to characterize differences in “impactor populations.” “The LRO LOLA impact crater database shows that the transition occurred about the time of the Orientale impact basin, about 3.8 billion years ago,” he wrote. “The implication is that this change in populations occurred around the same time as the large impact craters stopped forming and raises the question of whether or not these factors might be related.

“The answers to these questions have implications for the earliest history of all of the planets in the inner solar system, including Earth.”

It’s hoped that the workshop will provide an outreach to bring together diverse components surrounding the topic. Meanwhile, the concept of looking to the sky rather than below the earth for secrets to our planet’s history is an interesting one.

For more information, visit www.lpi.usra.edu/meetings/bombardment2012/

Channeling Art Berman, a former World Oil editor who lost his job after he became a closed-loop recording system decrying the plausibility of shale development, industry’s new “best friend” Ian Urbina of the Times seems dead-set on proving that oil companies are flat-out lying about the prospectivity of North American shale plays, despite the fact that most industry insiders consider the continent’s shale gas reserves to be the life preserver thrown to a drowning hydrocarbon industry. Citing internal e-mails from unnamed sources, among others, Urbina attempts to make the industry’s euphoria over its success in the shales seem like yet another attempt to dupe John Q. Public.

One weakness I’d like to point out in Urbina’s June 25 article, “Insiders sound an alarm amid a natural gas rush,” is that many of his sources data back to 2009. This isn’t ancient history, but so much has been learned in the last two years that yours truly would consider this information extremely outdated — i.e., not worth quoting.

For instance, he quotes an analyst from IHS Drilling Data as saying, “The word in the world of independents is that the shale plays are just giant Ponzi schemes and the economics just do not work.” That comment was made Aug. 28, 2009.

Another anonymous source, a retired geologist, said more recently that these “corporate giants” are having an “Enron moment.”

Yikes.

Additionally, he points to the rapid decline curve of many shale gas wells. This is common industry knowledge, not something I think anyone is trying to hush up, and the fact is that after astonishing initial IPs, some of these wells continue to produce respectable amounts of gas for decades. In the Barnett, for instance, he says production data indicate that the decline means that “many will become financially unviable within 10 to 15 years.” First of all, that’s a pretty respectable decline rate. Secondly, oilshalegas.com states that production in the Barnett may someday reach 3.4 Bcf/d, not bad for a bunch of junky little wells.

Additionally, he reveals that gas production data reviewed by the Times suggest that many wells may have more gradual decline curves, which is somehow portrayed as being a sinister fact.

Not surprisingly, the industry fired back immediately. Aubrey McClendon, CEO of Chesapeake Energy, took umbrage at the implication that it might be lying about its success in the shales on that company’s website. “Chesapeake stands behind all of its statements to shareholders, partners, and the public regarding our natural gas discoveries and production,” McClendon noted. “Our industry’s operations and investment decisions are informed and guided by the best geoscientific, petrophysical, and 3-D seismic data available and analyzed by some of the best drilling, completion, production, and reservoir engineers in the business. The results of the industry’s efforts to revolutionize natural gas development and production have been extraordinary and continue to improve.”

McClendon also jumped at the chance to showcase the naïve nature of the author’s economic conclusions, noting that the economics of today’s dry gas projects are worse – because of the abundance of shale reserves, not in spite of them. “It is also absurd to conclude that shale gas wells are underperforming while America is awash in natural gas and benefiting from natural gas prices less than half of what they averaged in 2008,” he wrote. “How can shale gas wells be underperforming if shale gas companies are beating their production forecasts, natural gas prices remain low, and US natural gas demand is at a record high?”

The Independent Petroleum Association of America’s “Energy In Depth” website issued the following rebuttal: “The United States produced more natural gas in 2010 than at any point in the previous 37 years, a stunning reversal of fortune given the country’s supply picture earlier this decade and one that could not have been possible without massive volumes of American energy that continue to be generated from shale.

“So what happens from here? By now, you’ve likely heard the stories and seen the estimates, with everyone from IEA to EIA to PGC to MIT projecting a future in which shale’s production trajectory continues along an aggressive upward path, delivering literally quadrillions of cubic feet of clean-burning natural gas to generations of consumers not only in the United States but around the world. It’s a view that’s supported by the preponderance of science and a majority of scientists, not to mention one that’s continuously reinforced by new data.”

Finally, I wish Mr. Urbina would take a step back and ask himself why companies would invest millions of dollars in horizontal wells and hydraulic fracturing if they secretly know that these wells are a waste of time and money. Why would huge companies like ExxonMobil, Total, and CNOOC invest in joint ventures or, in ExxonMobil’s case, simply buy a US independent if they didn’t think the shale had real potential? If they’re that dumb, Bernie Madoff could have a field day.

For a link to the latest Energy In Depth, visit http://www.energyindepth.org/2011/06/what-they%E2%80%99re-saying-36-hours-later/.

Advances in land seismic acquisition are moving at a dizzying pace, but advances in compute power have been even more rapid. Whereas once processing capacity lagged behind channel count, it has now outpaced it, and oil companies have responded by requesting more and more channels to more densely sample their onshore fields.

Recent numbers have been staggering – Global Geophysical shot a survey for ExxonMobil in the Piceance Basin that required almost 80,000 channels. CGGVeritas shot a survey in Qatar using 40,000 channels. And Kuwait Oil Company is planning a massive 220,000-channel survey.

Land geophysical contractors have already proven to be adept at keeping up with these demands, creating “Super Crews” that cover huge areas acquiring data 24/7. But these crews are still hampered by the sheer amount of equipment required to acquire these giant surveys.

Sercel proposed a solution at the recent European Association of Geoscientists and Engineers conference in Vienna. The Giga Transverse replaces standard transverses, which record the data from the sensors in the field. It increases the data transmission rate on the transverse from 100 Mb/sec to 1 Gb/sec, increasing the capacity from 10,000 channels to 100,000 channels at 2 milliseconds in real time.

“We have to bring more productivity and make it more affordable for our customers,” said Arnand Surpas, senior vice president of global operations for Sercel.

Reducing the number of transverse cable in the field also leads to simplified deployment, he said.

Sercel CEO Pascal Rouiller added that the new transverse is “critical for the growing Super Crew market for high-density wide-azimuth acquisition.” Literature from Sercel added that the 1 million channel milestone is “no longer a dream but a fast-approaching reality.”

A million channels will deliver a massive amount of data. Can the industry learn how to manage, analyze, and interpret that data? We’ll save that for another blog.

This was the message given by Tubagus Haryono, head of BPH Migas’ downstream regulatory body agency, at the recent Offshore Technology Conference. Speaking to a luncheon gathering May 4, Haryono said that Indonesia’s oil and gas industry is characterized by high risk, high capital demands, and high technology.

The country overall consumes about 1 MMbbl/day of hydrocarbons for industrial feedstock and domestic fuel needs and currently produces somewhat less than that. It has about 7.7 Bbbl of oil in reserves. One of the key issues is that, of the country’s 2.4 million people, 124 million of them live on the island of Java.

It also has 157 Tcf in reserves of gas and in fact produces more gas than oil. The gas reserves are 3.5 times that of the oil reserves, but they’re scattered. Currently an LNG plant in Kalimantan exports gas to other markets.

Most of the country’s reserves are offshore and are experiencing a very gradual decline. With this scenario in mind, Haryono said, the country hopes to encourage new investors to come to Indonesia to explore. Already there are three major deepwater projects in the works that will be coming onstream between 2014 and 2018. But they will face challenges, including water depth, high pressure, complex geology, and distance from infrastructure.

However, opportunities exist as well. The offshore has a big upside potential, and there are good incentives and strong government support. There’s also currently little competition, and the leases are controlled by the central government, not the local governments.

The country has identified several transportation projects that will help the country better meet its energy needs. It is planning to tie natural gas from Kalimantan to Java by pipeline, and it’s building a pipeline from East to West Java. There are also three projects for LNG receiving terminals on the drawing board. The country also intends to bring gas from a Petronas-operated field to supply electricity, and it’s currently exporting gas from Sumatra and Natuna to Singapore, with eventual hopes of building a pipeline across Kalimantan to Natuna.

Indonesia’s targets for 2025 are to maintain production of 1 MMbbl of oil per day, maintain security of supply, have 91% of the energy industry manned by local content, supply 99% of the skilled workers, and have a spotless HSE record. From the standpoint of potential foreign investors, the country offers great opportunities, high potential for unconventional reserves, and government goodwill in balancing national and investment interests, Haryono said.

“Don’t hesitate to invest your money in Indonesia,” he said.

This year’s American Association of Petroleum Geologists annual meeting was a little different. Yes, there were the usual seismic companies showcasing their multiclient data and software companies giving demonstrations. But there were also several companies discussing new ways to take rock samples from well cuttings and divine important reservoir information from them – at the wellsite.

One such company is FEI. Offering a concept known as “automated mineralogy,” FEI uses SEM and energy dispersive X-ray spectrometry combined with sophisticated software for image processing and automation. The result is a fully integrated mineral and rock analysis that is rapid, accurate, repeatable, and statistically valid, according to company literature.

Another announcement came from Fugro Robertson, which introduced its RoqSCAN technology at the show. RoqSCAN is a portable rock properties analyzer that looks at cuttings in high resolution and generates intuitive and quantitative mineralogical and textural datasets within an hour. Data provided include bulk mineralogy, lithology, mineral types and ratios, and grain size, all measured against depth. In stimulated wells, this information can be used to support the location of fracing stations.

Finally, I talked to PetroArc International, which evaluates an entire core sample without having to send it off to a core laboratory. Its TenEx imagery, said Vice President Nelson Heskett, represents a quantum leap in image resolution by measuring 1,360 dpi, the equivalent of looking at the core through a 10-x hand lens.

PetroArc’s core scanners are portable and can be ready for imaging at the wellsite within 30 minutes. The company also provides software that includes a wavelet-encoding algorithm to compress the imagery without loss in color fidelity or pixel resolution. And it can also image thin sections, core plugs, and cuttings.

The overall goal with these types of systems is to enable clients to stop relying on incomplete information. With this much detail coming directly from the wellbore, the hope is to provide operators the best reservoir information possible without the time and expense associated with traditional core analysis.

The sensing technology has a noise floor – a measure of the smallest detectable acceleration over a range of frequencies – of 10 nano-g per square root Hz, equal to the noise created by ocean waves at the quietest locations on Earth. Its sensitivity was tested at the US Geological Survey’s Albuquerque Seismological Laboratory, where it also picked up an earthquake in the Gulf of California some 800 miles away. The signal from the reference sensor was matched by the new sensor down to 25 mHz.

While Shell plans to use the inertial sensor for large land surveys, Paul Helm, worldwide program director, Manufacturing Industries, Upstream Solutions for HP, sees much wider potential. For instance, the sensors could be used in an ocean-bottom seismic system, and they could be useful as passive seismic monitors both for production monitoring and CO₂ sequestration. “There is a whole raft of opportunities,” Helm said. “This is a big advance in my view.”

The sensors could be used in pipeline monitoring to sense the buildup of wax and paraffin and alert operators to the location of the potential problem. Other uses include as a gravimeter, environmental monitoring, corrosion monitoring, and the calorific value of the fuel on a platform, he said. “You’d know exactly how much CO₂ you were putting into the air,” he said. “These sensors can generate a lot of data.”

In well construction, they could be useful in the drill string as well, gathering data from the BHA, wellhead, riser, or platform. In fact, Helm said that this could move the industry into predictive analysis – data collected from the well could help characterize how the drilling is going.

“In the wellbore, it can detect changes in fluid and improved gas-to-oil ratio, and it can predict onset – in other words, sensing patterns that have resulted in problems in previous wells,” Helm said. “You can see the pattern evolve, and your well might be following the same path.”

HP has come a long way since it provided gauges and metering devices on offshore platforms, he added. “We’re building off a strong legacy, and our clients are asking more of us,” he said. “There’s a constant pull to do more. Currently we’re saying, ‘Bring us a difficult problem.’”

For more information and to view a video about the earthquake experiment, visit http://67.19.218.130/~pnrsvp/richter/

Companies have dealt with this problem in the past by building scale models of their tools or construction projects, but these models can cost thousands of dollars to build. Austin, TX-based Zebra Imaging has a simpler approach – a holographic image.

Holograms are not new, but the sophistication of these images now allows them to have real use beyond simply a novelty item. According to Karen Hanley, product line manager for Zebra, the images have a variety of uses, from conveying technical concepts to non-technical people to trade show displays to sales presentations. For instance, FMC Technologies uses holograms to display 3-D renderings of some of their huge pieces of equipment. Not only does this save a tremendous amount of money, but it’s also a conversation starter. “We tend to see people come back to the booth three or four times and bring their friends,” Hanley said. “It’s that added stickiness – you can have a good conversation with them, evaluate the lead, and move the conversation along while making the booth itself more effective.”

She added that complex models more readily lend themselves to this approach than a 3-D model on a computer. “The complexity is really our sweet spot,” she said. “You can very quickly show a bunch of information, and the net-net is a faster time to decision, faster time to approval.”

How it works

The client provides Zebra with a 3-D data source such as an .obj file. The data is input into rendering software, and a preview is output for client approval. Once everyone has signed off, tiny holographic elements are recorded by lasers onto a specially designed film plate. When a light is shone on the plate, the elements emit thousands of points of light, giving the impression of a solid 3-D image.

The image appears to be about 6-10 in. above and below the plate, though that can be adjusted.

The plates are very sturdy, lightweight, and portable, and several can be combined for a larger image. At most they cost about US $3,500 each.

One of Zebra’s unique features is a process called “channeling,” in which the image changes depending on the angle at which it’s viewed. The plates can be set on revolving bases to demonstrate different phases of a building project, for example, or to illustrate water pipes in one view and electrical lines in another. And unlike the holograms of old that were bizarre combinations of red and green, the color renderings offered by Zebra can be quite bright or, in the case of a layout of a city, quite realistic. The plates can be lighted by a halogen or LED source.

Applications

Applications are almost limitless, but typical customers include the defense industry, the construction industry, architects, engineers and facilities designers, planners, and those needing a 3-D display for an exhibit or presentation.

A potential use in oil and gas is in safety training. Hanley showed a very realistic rendering of an offshore platform. Newcomers to the platform could use the image to familiarize themselves with its layout prior to actually arriving on the scene, and evacuation procedures could be reinforced during safety meetings.

The company has a new motion product in development, and it continues to innovate as customers find more uses for the technology.

“We’re really responding to that next wave of customers,” Hanley said. “They’re always saying, ‘Hey, I could use this for such and such.’ But you really have to see it to believe it.”

Caption:

Zebra Imaging has created a realistic 3-D hologram of a Mustang offshore drilling rig. (Image courtesy of Zebra Imaging)

Smit talked to a group of journalists in Houston about his belief that we are close to a paradigm shift in petroleum exploration. In the past, upstream technology has lagged behind upstream business, but now it’s possible that new technology can actually drive business opportunities, he said.

“We need to start thinking about how we can manipulate the subsurface,” he said.

To do this will require much more data than is currently being acquired, and that in turn will require some serious technological breakthroughs. For geoscientists who are already swimming in data, this may sound like too much of a good thing. But Smit said that current seismic methods require many different inputs just to constrain the model. In shales, for instance, he said that more sophisticated reconnaissance techniques like seismic are still in their infancy when it comes to predictive power.

Current seismic methods require significant redundancy just to convert time to depth, for instance. And often it’s still not enough. He showed an example of a dry hole in the Gulf of Mexico that was drilled based on geological assumptions. Despite the optimism of the geosciences team, who thought the well had a 70% probability of success, it was drilled into a fault and didn’t find any sands.

“Sometimes you don’t know when it doesn’t work,” he said, adding that it’s hard to justify a multi-million dollar decision on a technology that lacks predictive capability.

Smit is not a peak oil proponent; he maintains that there is still an abundance of oil and gas in the world, but it can’t be imaged with current technology. He likened it to medicine in the old days where a surgeon would cut a person open just to figure out what might be wrong.

Finding more oil is also going to require a change in mindset. The traditional method of finding oil and gas doesn’t necessarily require sophisticated tools; it just requires a decent geological understanding.

“This concept is going to have to change,” he said.

The change is likely to resemble the change in compute power that has led to Moore’s Law, the idea that computing power doubles in speed every two years without an attendant increase in price. This was possible due to the miniaturization of computer parts, and Smit said a similar thing will happen in the sensor industry. On a graph charting Moore’s Law against channel count, Smit showed that those lines crossed in 2007, meaning that now sensors have to catch up with computers and not the other way around.

Onshore, getting the type of data sampling that Smit believes is necessary (1 million channels) is impossible with a cabled system. This will call for what he terms “consumer seismic” – cheaper systems, more efficient storage, new algorithms, and an “Internet” of sensors that can communicate with each other and interact in real time.

To this end, Shell has a couple of research initiatives. One is with PGS, applying its OptoSeis fiber-optic marine sensor technology in an onshore setting. So far the system has been tested in Oman, and it will be in production soon. It’s reeled off the back of a truck and provides comparable data at a fifth of the cost of a traditional cabled system.

Shell is also working with HP on a MEMS sensor that can take 200 samples per second. The sensor was compared to a seismograph when sensing an earthquake and provided superior results.

In both cases, Smit said, “It’s possible to increase density while reducing cost.”

He envisions a continuous monitoring solution that would be a hybrid of many different measurements and would turn the wells themselves into sensors. Passive seismic, recorded constantly, would provide a “backbone” for more periodic active surveys.

Overall, consumer geosciences will need to consist of:
• Better rock physics relationships;
• Better resolution;
• Hybrid permanent systems;
• Faster imaging with no approximations; and
• Faster visualization.

“We need more, faster, and cheaper all at once,” Smit said.

According to “The Hill,” Sen. John Barrasso (R-Wyo.) has blasted the panel members for not being experts on offshore drilling. “They weren’t experts on oil drilling in the Gulf,” Barrasso told a reporter on CNBC. “It was a self-selected group that really opposes drilling in the Gulf, and they came out with the recommendations that you would expect that group of people to come up with. And those are all things that are going to make energy more expensive.”

Even more troubling are the some findings themselves, which oilfield operations expert Phil Rae says are flat wrong. What the panel claimed was a leak in the annular preventer was actually the result of the well flowing.

“The commission reports the crew on the Deepwater Horizon saw the fluid level in the riser fall, realized they had a leak through the annular preventer, and topped off the riser with mud,” Rae said. “Yet that didn’t happen.”

What did happen was that the pressure increase in the riser was assumed to be a leak but was actually the well flowing to the surface. “If the crew hadn’t assumed there was a leak, they would have likely realized that the well was live and taken appropriate measures.”

He added that the real reason the rise needed topping off was because the casing shoe failed during mud displacement with spacer, so the well lost mud. “This is the actual reason the well went live, and it’s important to understand this nuance if we hope to mitigate the risks of future blowouts,” Rae said.

Another error, he said, is the report’s statement that running a long string rather than a liner was an acceptable design choice. “There are specific reasons BP should never have run a production long string on this well (or any other deepwater well). Yet nobody has voiced these concerns, so we can only assume the same mistake could be repeated any time.”

Unfortunately, Congress in general is even less expert in offshore drilling than the president’s panel. It’s feared that we won’t learn much from this mistake.