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THE Fracking Thread pt 3

Discussions of conventional and alternative energy production technologies.

Most water injected in shale isn't available for recycling??

Unread postby misterno » Tue 06 Dec 2011, 13:26:57

http://online.wsj.com/article/SB1000142 ... %3Darticle

CARRIZO SPRINGS, Texas—Water has always been a concern for 65-year-old Joe Parker, who manages a 19,000-acre cattle ranch here in South Texas. "Water is scarce in our area," he says, and a scorching yearlong drought has made it even scarcer.

Mixing Oil and Water
See projected fracking water usage in 122 major Texas counties in 2010, 2020 and 2030, and the percentage of water wells in Texas that are oil-related.

View Interactive
.More photos and interactive graphics
.Enlarge Image

CloseRussell Gold/Wall Street Journal

A landowner offers water for sale outside Carrizo Springs, Texas.
.What has Mr. Parker especially concerned are the drilling rigs that now dot the flat, brushy landscape. Each oil well in the area, using the technique known as hydraulic fracturing, requires about six million gallons of water to break open rocks far below the surface and release oil and natural gas. Mr. Parker says he worries about whether the underground water can support both ranching and energy exploration.

Darrell Brownlow, another cattle rancher, says that if the economically depressed region has to choose between the two, the choice should be simple.

Mr. Brownlow, who has a Ph.D. in geochemistry, says it takes 407 million gallons to irrigate 640 acres and grow about $200,000 worth of corn on the arid land. The same amount of water, he says, could be used to frack enough wells to generate $2.5 billion worth of oil. "No water, no frack, no wealth," says Mr. Brownlow, who has leased his cattle ranch for oil exploration.

Hydraulic fracturing, or fracking, has revived prospects for oil-and-gas production in the U.S. and provided a welcome jolt to many local economies. Less than three years after its discovery, the Eagle Ford oil field here already accounts for 6% of South Texas's economic output and supports 12,000 full-time jobs, according to a study by the University of Texas at San Antonio earlier this year, which was funded by an industry-backed group.

But fracking also is forcing communities to grapple with how to balance the economic benefits with potential costs. To date, criticism of fracking has focused mainly on concerns that the chemicals energy companies are mixing with the water could contaminate underground aquifers. Oil industry officials regard that issue as manageable. The biggest challenge to future development, they say, is simply getting access to sufficient water.

The issue isn't just rearing its head in parched regions like South Texas. North Dakota, another big source of oil from fracked wells, is concerned about the industry depleting aquifers and has threatened to sue the federal government to free up water held by an Army Corps of Engineers dam. Oklahoma, too, is struggling to cope with the industry's thirst.

Last year, Louisiana passed a law to regulate what it called the industry's "unprecedented use of enormous amounts of water" that, if unchecked, has the "potential for chaos and conflicts." In northern British Columbia, which has plenty of water, officials have required companies extracting natural gas to install expensive equipment to recycle water used for fracking. It wasn't a pollution-control effort, but a response to local communities that didn't want their water supplies tapped.

In Pennsylvania, the industry and state regulators have cracked down on the amount of salty water from fracking jobs being sent to water-treatment plants that weren't designed for it. A large amount of this water is now being recycled and reused, cutting down on the amount of fresh water needed to continue developing new wells.

Fracking involves drilling deep into large swaths of dense rock where oil and gas are trapped. To crack the rocks and allow the oil or gas to flow out, energy companies inject millions of gallons of water, mixed with sand and chemicals, at high pressure.

After sending natural-gas production soaring, hydraulic fracturing now is playing a critical role in the dramatic rise of oil production in Texas and North Dakota. Many industry officials believe it will allow Ohio to become a major oil producer, and other states could follow. Oil imports are falling, prompting talk of slashing U.S. dependence on foreign energy sources.

Enlarge Image

Close.Here in South Texas, tensions are rising as companies scramble to lock up water to drill natural-gas and oil wells. All across the state, companies have been on a buying spree, snapping up rights to scarce river water—easily outbidding traditional users such as farmers and cities. Led by Exxon Mobil Corp., they also are drilling water wells, three times as many as they did five years ago. They are even tapping into municipal water systems, though parched cities have begun cutting them off.

There is no disputing that the boom has been terrific for the local economy, and few residents are calling for an end to fracking. Demand for workers is so high that Carrizo Springs resembles a hastily built labor camp, with thousands of temporary workers filling up a dozen new recreational-vehicle parks. The city's population has nearly doubled to about 11,000 in the past two years, say local officials. Sales-tax revenue in Dimmit County in 2011 is expected to exceed the previous five years combined. The University of Texas at San Antonio study predicted that, by 2020, the oil field will support 68,000 jobs, and its economic output will increase nearly ninefold.

Compared with demands from cities, farmers and even power plants, the amount of water needed to develop oil and gas wells in Texas is small. In September, the Texas Water Development Board released a draft of the 2012 Texas water plan—a report prepared once every five years. It said 56% of water in Texas goes to commercial crops; 26.9% to cities and public-water systems; 9.6% to manufacturing, including refineries; 4.1% to power generation; 1.8% for livestock; and 1.6% to mining, which includes oil-and-gas drilling.

But the report noted that the rise of fracking has been so sudden and steep that it wasn't really integrated into the report. In addition, the oil-industry's water use is concentrated in select parts of the state, magnifying the impact in those places.

Fewer than 2,000 oil and gas wells have been drilled in the past couple of years in South Texas. The industry expects that number to climb to as many as 25,000 over the next couple of decades.

Eagle Ford oil wells are the most profitable of the thousands being drilled into shale rocks nationwide each year, according to an analysis by Credit Suisse Group.

Because of the geology of the Eagle Ford, each oil or gas well there uses the equivalent of 10 Olympic swimming pools' worth of water—nearly twice as much as needed for wells in the Barnett Shale field in North Texas, according to industry and academic data. Most of the water injected into shale wells nationwide is absorbed by the rocks and isn't available for recycling. At the Eagle Ford, practically none of it is recycled.

Most Eagle Ford wells draw water from the Carrizo aquifer. That aquifer "is already stressed, and now you are adding an additional demand," says Ronald Green, a hydrologist at Southwest Research Institute, a nonprofit research-and-development organization in San Antonio that does scientific analysis for the government and industry.

Studies by hydrologists and geologists suggest more than twice as much water in recent years has been drawn from the aquifer as has been recharged by rain. And that was before the Eagle Ford energy boom started.

Last year, oil companies drilled 2,232 new water wells throughout Texas, about three times as many as five years earlier, according to a Wall Street Journal analysis of Texas Water Development Board records. More oil wells are expected, and as the industry refines its techniques and drills longer wells, the amount of water used for each well is climbing.

The oil industry has long believed that its thirst for water could cause problems. The American Petroleum Institute, a Washington-based industry trade association, warned against using fresh water for fracking in its 2010 best-practices advice. In an email, the institute said the industry should consider nonpotable water "whenever practicable," but decisions must be made on a "case-by-case basis."

Some companies are taking steps to use less potable water. Anadarko Petroleum Corp. says it is exploring whether it could extract water from a deep, salty aquifer unfit for people or crops. Devon Energy Corp. has begun recycling a small percentage of the water it uses for fracking.

"We need to be ahead of the curve on some options should there come a time that water is not so readily available as it is today, through drought or regulatory issues," says Jay Ewing, a Devon manager in North Texas.

In Texas, the industry's thirst puts it in direct competition for water with traditional users, which already are drawing more water from aquifers because of the drought. Ranchers have had to lower the pumps in their wells to find enough water.

Kenneth Braden, a 61-year-old rancher who raises cotton southeast of Midland, Texas, says his water wells now pump half as much as last year. He blames the drought and what he says is the "overwhelming" amount of water used for fracking.

Mr. Braden doesn't favor shutting down the wells, which he realizes provide lots of jobs. He says he wants the companies to figure out ways to use fewer gallons. He has tried to raise the issue with them, he says, but hasn't gotten a response. "They're just so much bigger and more powerful than we are," he says. "We're just kind of the little ant that gets squashed."

Under Texas law, an oil company that has the mineral lease on a property has the right to tap aquifers without the consent of landowners.

Dan Waldrop owns 1,200 acres in LaSalle County, about halfway between San Antonio and Laredo, but he doesn't own the mineral rights. The energy company that does has drawn nearly 30 million gallons of water so far from a well it drilled on his property.

He says he is considering trying to make the company pay for it. "In the deed, it says they have the use of the water, and it doesn't say they have free use," he says.

In addition to tapping underground aquifers, oil companies are interested in water from Texas rivers. They have acquired—or are currently seeking to acquire—from local irrigation authorities the rights to nearly 40,000 acre-feet of water a year. That is enough to supply nearly a quarter-million people for a year.

One source has been the Rio Grande. Cities along the river, which are among the fastest growing in the state, draw from it to supply water to residents.

"This is a major concern for us," says Juan Hinojosa, a Democratic state senator from McAllen who represents the area. "The oil companies have a lot more money than we do to buy water rights."

The intense drought over the summer exacerbated the water concerns of cities. More than 964 public water systems, covering 14.7 million Texans, have imposed voluntary or mandatory restrictions, according to the state.

This summer, the city of Grand Prairie, near Fort Worth, stopped selling water to oil companies as part of its drought-contingency measures, which also included lawn-watering restrictions.

Oil companies have long been exempt from most Texas state water rules and permitting requirements, but the state has begun to take a fresh look at the industry's ability to drill water wells wherever they have acquired rights to extract oil and gas. Texas oil regulators have convened a task force to look at a range of issues related to the Eagle Ford boom.

"The No. 1 issue is water," says David Porter, a Republican member of the Texas Railroad Commission, which regulates the oil industry and is seen as generally pro-development. "Everyone is concerned about water." The task force expects to issue recommendations on water next year.

Even people such as Mr. Parker, the rancher worried about water depletion, find it tough to resist the cash oil companies are offering. In South Texas, the water needed to frack a single well can fetch more than $50,000. Mr. Parker decided to sell his water. "If they didn't get it from me," he says, "they would get it from my neighbor."

Mark McPherson, a Dallas-based water-rights lawyer who has represented both ranchers and oil companies, expects conflicts over water to increase as hydraulic fracturing expands. Texas resource-development laws are designed to encourage the oil industry to produce as much as possible, he says, but in recent years, the state's water use rules have been geared toward conservation.

"Those two fundamental philosophies are diametrically opposed to each other," he says. "They are in conflict from the get-go."
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Re: Most water injected in shale isn't available for recycli

Unread postby PrestonSturges » Tue 06 Dec 2011, 14:32:37

Anyone remember the bright orange streams and reservoirs from acidic coal mine drainage? Those organic compounds have been down there doing their chemistry in the absence of oxygen for millions of years. Heck that's why oil has value as fuel - we get to bring it up so we can burn it (oxidize it) in our cars. There are going to be lots of other chemical in that water, just waiting to react with oxygen and create new compounds.
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BTEX chemicals in fracking - how are they replaced?

Unread postby alokin » Sun 23 Mar 2014, 17:17:58

Apparently, BTEX chemicals will be banned in Australia (pdf link http://www.resources.nsw.gov.au/__data/assets/pdf_file/0003/400728/Minister-Hartcher-med-rel-end-of-moratorium.pdf
How will they replace these chemicals and how dangerous are the replacements?
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Shale Oil secondary recovery

Unread postby dashster » Wed 20 Aug 2014, 21:18:48

This way be way off the mark, but I was wondering if fracking shale allows you to recover a higher percentage of the oil in the ground versus pumping it out of a conventional reservoir?

They drill down and then horizontally. Then they pump in water, chemicals and sand to fracture the rock. Can they, by continually drilling new horizontal wells a caculated distance below the previous one, end up getting a higher percentage of the oil underground than conventional crude pumping gets? And if they can continue to get oil out of the same original vertical hole drilled, wouldn't that mean that the decline rate from a fracking well can go negative when the next horizontal well is drilled?
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Re: Shale Oil secondary recovery

Unread postby ROCKMAN » Wed 20 Aug 2014, 23:02:12

Dashter - As a general rule recovery of in place reserves in the shales tends to be much lower the conventional reservoirs. But RF for conventional reservoirs can run from 10% to 70%+ with secondary efforts. Not any real secondary recovery from hz shale wells per se. But frac'ng the same well a second time can be a good investment. They learned that in the Barnett Shale years ago. But a good investment because a refract is much cheaper then the original drilling and frac'ng. The second frac doesn't tend to produce nearly as much as the first but the return on investment can be much better.

The way to enhance the recover from an area is a tighter spacing of the hz wells. But as you imply if the wells get too close they'll start draining the same fractures and that hurts the return on investment. The reason the shale wells decline so fast is two fold. First, fractures tend to flow oil/NG much faster then a conventional reservoir. OTOH the individual fractures in a well tend to hold a much smaller volume of hydrocarbons per unit area so the flowing pressure drops very quickly and thus the very high decline rates. Often even when an Eagle Ford well starts flowing hundreds of bopd on it's own they often start setting an artificial lift system on the well. It won't take long for the reservoir pressure to drop too low for the oil to move up the production tubing under it's own power. That's runs the production cost up significantly at the same time cash flow is falling like a rock.
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Re: Shale Oil secondary recovery

Unread postby dashster » Thu 21 Aug 2014, 19:40:54

Thanks for the reply.

ROCKMAN wrote:. But frac'ng the same well a second time can be a good investment. They learned that in the Barnett Shale years ago. But a good investment because a refract is much cheaper then the original drilling and frac'ng. The second frac doesn't tend to produce nearly as much as the first but the return on investment can be much better.


So if you frack a well a second time, is the "decline rate" of an existing well considered to have gone negative or is it considered a new well?

The way to enhance the recover from an area is a tighter spacing of the hz wells.


Does each horizontal well require a new vertical well?
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Re: Shale Oil secondary recovery

Unread postby ROCKMAN » Thu 21 Aug 2014, 21:00:40

dashter - IN Texas (and probably all other states) each well has a unique ID number: the API number. Re-facing a well or recompleting to a different shallower reservoir doesn't change the API...same well. Not a negative decline rate per se. For example a frac'd well declines to 8 bopd. Then they frac it again and it's producing 120 bopd. And that's what the plotted production curve looks like: the line declines and the shoots back up. The cumulative production will include all production from every frac treatment.

Does each horizontal well require a new vertical well? All hz wells start as a vertical well. Picture a straight hole drilled from the surface to 7,000. Then the start "building angle": begin digesting the drill pipe from vertical. Build rates can very greatly: changing the hole angle by 2 or 3 degrees for every 100' drilled and a "short radius well" building at 15 to 20 degrees per 100' drilled. So depending on the build rate anywhere from few hundred feet to 1500 of hole is drilled until the well bore is horizontal. So when you see that a well has a "3000' lateral" it means that 3000' of hz hole was drilled. The vertical depth of that lateral may be a few thousand feet to 14,000'+. For instance a 3000' Eagle Ford Shale lateral could be composed of 6000' of vertical hole with 1000' of "build section" followed by the 3000' lateral. So in total 10,000' of hole was drilled to produce that 3000' completion in the EFS.

Here's a bunch of pictures to put some meat on the bones I described above: https://www.google.com/search?q=directi ... 84&bih=384
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Re: Shale Oil secondary recovery

Unread postby sparky » Fri 22 Aug 2014, 00:26:15

.
Good stuff as usual Rockman , It can be useful though not really accurate to model a secondary fracking as boosting the flagging production back to half the initial production of three years before , the decline is a bit steeper
any third or fourth fracking give decreasing return for even shorter time
this is a mental model as a ( very ) rough reckoning .
there are economic and technical limits to how far one can push the horizontals ,
also some legals constraint or else one could be sucking someone else lease
horizontal drilling by Koweit in a field on the border with Iraq upsetted Saddam enough to be one of the reasons there was the first gulf war , it wasn't the only one but being seen as sucking someone else juice is very serious aggro
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Re: Shale Oil secondary recovery

Unread postby ROCKMAN » Fri 22 Aug 2014, 09:54:25

Sparky - Some might be surprised how far they've pushed the hz tech. For some years now Maersk has been drilling 30,000'+ laterals in the Al Shaheen Field in the Persian Gulf. At one time I was trying to get a gig geosteering them but my MS ended that possibility. Besides distances imagine this: a well drills vertically down to 6000' and then builds angle drilling north until it's at 45 degrees and 3000' north of the surface location. And then it drops angle to vertical and then starts building angle going SOUTH and then lands at 90 degrees and drills a hz hole directly under your surface location. Such geosteering is often done offshore when you're restricted to drilling all your wells from the same surface location. And the direction plan I just described isn't nearly as complicated as some I've steered.
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Re: Shale Oil secondary recovery

Unread postby sparky » Sat 23 Aug 2014, 17:17:34

.
Whoa .... 30,000' , that's in the 10 klicks range ...... amazing ! it's on par with some pre-salt lenght
a few years ago that would have been the stuff of legend and nowaday it's like " all in a day job "

what would be the ball park for the continental US tight oil fracking ? the drilling density must be optimized
I suppose the cost /return must be watched by the bean counters like hawks
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Re: Shale Oil secondary recovery

Unread postby copious.abundance » Wed 24 Sep 2014, 21:07:38

Wood Mackenzie: US Tight Oil Technology Could Boost Output by 25%
There continues to be great potential for surprises to the upside in production of U.S. tight oil according to Wood Mackenzie's latest integrated analysis.

"Growth in U.S. tight oil continues to impress as development technology and techniques have yet to mature beyond adolescence," said Phani Gadde, Senior North America Upstream Analyst for Wood Mackenzie.

To better illustrate, Gadde said additional volumes from Enhanced Oil Recovery (EOR) will come on stream after 2020, and could add 1.5 to 3 million barrels per day (mb/d) by 2030, up to 25 percent more oil than is being forecasted today. These technologies are in early test phase and not commercial yet, but indicators suggest up to a 100 percent increase in recovery rates. There are pilot tests that are underway with operators like EOG testing it out in the Eagle Ford adds Gadde.

[...]
Stuff for doomers to contemplate:
http://peakoil.com/forums/post1190117.html#p1190117
http://peakoil.com/forums/post1193930.html#p1193930
http://peakoil.com/forums/post1206767.html#p1206767
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Re: Shale Oil secondary recovery

Unread postby shallow sand » Thu 25 Sep 2014, 21:49:29

Copious. Why are the majors not big players in the shale oil story? I realize there are some pretty big independents such as EOG, Devon, Whiting, Pioneer, Continental and others. I figured by now there would be more buyouts by the likes of Exxon, Chevron, Shell and BP. I guess there was Exxon XTO and Marathon and Conoco Phillips are operating in the shale areas. Are the big independents wanting to stay independent or are the majors not interested in buying them? Would think some of those I mentioned would be buyout targets now, especially since the crude price pullback has dropped their shares much more than the majors. In the past the independents would find the elephants and then sell to the majors, who would develop them. This boom seems different in that regard. I'm still not entirely sold as to the shale story being long lasting, but I am trying to look at this from all angles and do admit that the production spike is incredibly impressive
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Re: Shale Oil secondary recovery

Unread postby ROCKMAN » Fri 26 Sep 2014, 08:31:24

sparky - "...what would be the ball park for the continental US tight oil fracking ?" I doubt we'll ever see laterals approaching that length in the US. The unique situation for Maersk is that the Al Shaheen Fld contains huge NG reserves but is located offshore. If it weren’t for the need to drill from platforms I doubt they would be drilling that far: just more economical then to set dozens of additional platforms.

shallow – Just a generality but Big Oils would acquire Little Oils for two reasons: to gain their proved producing reserves and because the Little Oils became vulnerable and thus are willing to cash up and go away. The problem Big Oil has with the current crop of Little Oils is there focus on short lived INDIVIDUAL well reserves. The EFS et al may be drilled for years ahead. But if ExxonMobil et al had wanted to be drilling in those trends they could have easily outbid Little Oil for those leases. XOM could have taken every lease that Chesapeake acquired if they had wanted to invest in drilling. Even the big DW GOM fields aren’t as strong draw for Big Oil acquisitions because of their relatively short lives. If some Little Oil had 10+ years of solid proved producing reserves Big Oil would pay a huge premium for them.
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Re: Shale Oil secondary recovery

Unread postby rockdoc123 » Fri 26 Sep 2014, 14:58:48

shallow – Just a generality but Big Oils would acquire Little Oils for two reasons: to gain their proved producing reserves and because the Little Oils became vulnerable and thus are willing to cash up and go away. The problem Big Oil has with the current crop of Little Oils is there focus on short lived INDIVIDUAL well reserves. The EFS et al may be drilled for years ahead. But if ExxonMobil et al had wanted to be drilling in those trends they could have easily outbid Little Oil for those leases. XOM could have taken every lease that Chesapeake acquired if they had wanted to invest in drilling. Even the big DW GOM fields aren’t as strong draw for Big Oil acquisitions because of their relatively short lives. If some Little Oil had 10+ years of solid proved producing reserves Big Oil would pay a huge premium for them.


My view based on interacting with the likes of Shell and Exxon in various shale gas conferences is the reason Big Oil isn't there very much is they do not have the cost control discipline. Exxon is famous for gold plating their operations, independents avoid partnering with them for that very reason. Shale oil/gas success is predicated on a manufacturing model where you use efficiences to manage costs downward. Exxon bought XTO to acquire not just their acreage but their expertise. Within a year all the XTO expertise left and went elsewhere as they couldn't deal with the Exxon mentality. This is largely why the shale gas story in Argentina is likely to go belly up. Rather than invite in the small independents who understand cost management the government pushed to get Exxon, Total, Shell, Chevron all involved in the industry. Given YPF's difficulty in finding their own backsides with both hands I suspect they will be mesmerized by all the high tech talk from the majors...until they see the bill.
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Re: Shale Oil secondary recovery

Unread postby shallow sand » Fri 26 Sep 2014, 23:03:39

Rocdoc I can understand how the independents can do this cheaper. However, where else can the majors go? Arctic Russia? Tar sands? Deep Water? I'm not informed as to how projects like these make more sense other than the scale is so big they are the only ones who can do them. Seems like they could very well be even more expensive per bbl than shale, but that is just a guess on my part.

Is it true that costs are going down in the shale plays and they are getting more efficient? Or is that more hype than fact. CLR released numbers that cost per well went up, which seems contrary to what has been reported, although suppose that could be due to things which make wells more profitable. Would seem cost per bbl would be more relevant long term anyway.

I am surprised there are enough qualified workers to keep the shale boom growing in the USA. There are a lot of people who want/need a job, but most lack the skills. Labor is usually a big cost driver, even in a capital intensive industry like upstream. Would seem difficult to drive costs down if everyone is fighting over a limited labor force. In our small world every experienced person has seen their wages go up big time since about 2005, and there is no shale boom where we are. I'm ok with that, as those that hung on through the 1990s should get a reward. Just find it hard to believe that costs are being driven down with a high number of rigs running.
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THE Fracking Thread pt 3

Unread postby sparky » Wed 15 Oct 2014, 06:18:52

.
Rockman , your caveat about uncertainties is certainly to your credit but let's nor muck around
a 20% drop in price in three weeks is very bad news for the producers , all over the industry
especially as this is not a quick market move but a deliberate position taken by the biggest exporter on the world market ,

the last time they pulled this stunt back in the 1980ies the US oil industry went to financial Siberia for nearly ten years
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Re: THE Fracking Thread pt 2 (merged)

Unread postby ROCKMAN » Wed 15 Oct 2014, 09:12:14

Doc - "...the control on financing by oil price that is the worry...". I agree completely. I didn't have time to detail but you've highlighted the critical factor: herd mentality of financing sources. IMHO EOG is one of the best shale players out there. Yet their stock has taken a hit. And while we don't have access to their finance arrangements it's probably a good bet their credit lines have been reduced. Which is unfortunate because the slide in oil prices might make for a juicy hunting ground for them to acquire the less successful players. But difficult to do with less credit. And like the Rockman they'll also benefit from cheaper costs as a lot of other companies drop drilling plans. But will they be able to take advantage of that situation? I'm about to start dangling lower priced contracts in front of the drillers as they start holding their breath waiting for their rigs to be released by the EFS players. The oil price slide could not have happened at a better time for the Rockman's company.

Sparky - I couldn't forget the slide in the mid 80's if I had a lobotomy. LOL. So little consulting work I was delivering produce to restaurants using my p/u truck for $50/day. But now my situation is very different as I just described to Doc above. Working for a billionaire, who doesn't need to borrow to drill, the price slide (which he and I don't expect to last more then 2+ years) will be very beneficial. And I was just asked in a PM why I'm not distraught over the effects of the price slide on other companies. Which makes me wonder how many others wonder the same. It's really very simple: we ARE NOT some brotherhood where it's one for all and all for one. We are competitors. Any event that cripples other companies and benefits mine is a good thing. And if those events that lead to a fall off in US oil production in a few years when we plan to liquidate the Rockman's then it's double good: both our competitors and the public ultimately get screwed. LOL.

Again, it isn't personal... just business.
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Re: THE Fracking Thread pt 3

Unread postby Graeme » Wed 15 Oct 2014, 16:03:35

Has OPEC Check Mated US Shale Producers

Crude prices have been tumbling lately.

Brent crude, the global barometer, fell below $90/ bbl while WTI has tumbled lower to about $85/bbl. Pundits who extol conventional wisdom have been in a froth. As giddiness about US shale production emerged over the past few years, these pundits proclaimed that the shale revolution would make the world awash in oil but prices would not come down due to geopolitical events. This is a typically narcissistic view. They recently began boasting that the U.S. had now passed Saudi Arabia and Russia to become the world’s largest producer. What they neglected to brag about are the underlying fundamentals of this shale revolution: the junk debt, the deteriorating financials, the rapid depletion of wells and the difficulty of raising capital as large sophisticated investors quietly exit the back door. But perhaps most damning is the comparison of costs with Saudi and Russian projects. This is truly the Achilles heel of US tight oil. An aspect which typical conventional wisdom pundits in the US rarely address. And this has more to do with the decline in crude prices than they care to admit.

The math is really quite simple. If you’re in business to sell hydrocarbons, the point is to extract them at the most cost effective price, have long term supplies that are dependable and then control supply to effectively manage the market price. OPEC is very good at just this sort of model. So faced with the prospect of losing market share to tight oil producers in the US, OPEC has simply taken the most prudent business decision. Keep the taps open. Why? Because U.S. tight oil producers really can’t compete in the global markets in spite of all the hyperbole. Their costs are just too high. And OPEC knows this.

IEA, the International Energy Agency based in Paris which analyzes the global crude markets, stated in a recent report that U.S. tight oil costs an average of ~$85/bbl. Other market analysts put this figure much higher even exceeding $110/bbl. Juxtapose this with the cost of a barrel of Saudi crude which is estimated to cost about $10-25/bbl. Therein lies the problem. In order to protect market share, the Saudi’s have decided to keep producing at current levels. They are still making a good profit whereas the U.S. producers cannot break even with crude below an average of $80/bbl at best.


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Human history becomes more and more a race between education and catastrophe. H. G. Wells.
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Re: THE Fracking Thread pt 3

Unread postby shallow sand » Wed 15 Oct 2014, 21:50:42

I'm not good on posting links but look at the EIA information released 10/14 on the major oil and gas basins in the US. Legacy production decline for Eagle Ford, Bakken, Permain hit 200,000 bbl per day. Also appears that longer laterals lead to higher IP but steeper decline, therefor maybe not much greater ultimate recovery. I know it won't happen and simplistic calculation that does not take into account lessening of decline each month, but is it correct that complete stoppage of drilling in these three areas would cause a decline of 1.5-2 million bbl per day in one year? That is incredible if even close to accurate.
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Re: THE Fracking Thread pt 3

Unread postby ROCKMAN » Wed 15 Oct 2014, 22:27:02

Shallow - I haven't tried to model that potential decline nor have I seen anyone else post enough DOUMÉNTED support data for their prediction. But there's two primary components. The older wells that have already gone thru their high decline rate and are depleting slowly now. They might be averaging less than 100 bopd... maybe a good bit less. But they represent 1000's of wells so collectively they represent a significant base that isn't decline very fast now. On the other side of the calculus are all the new wells that initially produce at a much higher rate. Obviously if all new drilling stopped we would see an immediate stop in production increases followed by a rapid decline characteristic of new wells. But obviously we won't see the rig count drop to zero overnight or even in a few months. And that's where models will vary greatly: 20% drop in rig count in 6 month? 40%? 60%? 80%? Or maybe just enough rigs running to keep the rate flat for a while?

A smart guy can know the answer to a question. But a really smart guy knows what he doesn't know and avoids making an unsupported guess.
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