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Permalink Reply by James Vanderink on October 7, 2013 at 1:47pm

Amazingly the oil window has disappeared. Don't believe this nonsense. Do your research in western Guernsey, Muskingum , Coshocton, Holmes and Yes Tuscararus........ it will happen soon. Let me throw in Wayne county also.

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Permalink Reply by Chris on October 7, 2013 at 2:44pm

No one has figured out how to drill the oil window, that's the problem.  So far nobody wants to throw money down the tubes like Devon did.  The few wells that have been drill in Tusc have been lackluster at best, hopefully someone can figure it out

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Permalink Reply by Jim on October 8, 2013 at 4:54am

Devon didn't throw money away.  Devon drilled some bad wells, took a loss in the first quarter of 2013 and then repatriated two billions dollars from off shore at a lower tax rate.  There's profit in drilling bad wells.  In my speculative opinion.

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Permalink Reply by 0i7okn54zwbdo on October 8, 2013 at 6:22am

Devon threw money away, it just wasn't theirs.  

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Permalink Reply by James Vanderink on October 10, 2013 at 6:41am

Jim, talk about a tax right off!!

Devon takes it on the chin in the Tuscaloosa Marine Shale

Goodrich Petroleum Corp. has acquired a major stake in 277,000 acres in the Tuscaloosa Marine Shale, with plans to step up drilling activity in the area.

Goodrich acquired Devon Energy Corp.’s two-thirds share of the 277,000 leased acres in the Tuscaloosa for $26.7 million. The deal lifts Houston-based Goodrich’s holdings to 320,000 acres in the Tuscaloosa and makes the company the largest player in the formation.

Goodrich President and Chief Operating Office Robert Turnham Jr. said Tuesday that the company will spend $50 million this year drilling wells in the Tuscaloosa, but plans to kick up its activity on the newly acquired acreage.

Goodrich could spend as much as $150 million on Tuscaloosa wells in 2014.

“Under the right scenario, we would love to even double that number and spend as much as $300 million,” Turnham said.

The Tuscaloosa, which stretches across the state’s midsection and to eastern Mississippi, could produce an estimated 7 billion barrels of oil. Industry members and public officials believe the formation could launch the same kind of economic boom in this region that the Haynesville Shale — a mostly natural gas formation — did in the northern part of the state.

Goodrich believes it has “cracked the code” on how to complete wells in the Tuscaloosa, from where to land the horizontal drilling sections that span out from a well to the recipe for fracking fluid used in cracking rock formations to release trapped oil and natural gas. And Goodrich believes it can apply that code to about 75 percent of the leases it just bought.

If recent results are any indication, Goodrich has reason to be confident.

Goodrich’s Crosby well, in Wilkinson County, Miss., produced an average of 1,137 barrels per day during its first 30 days of production. Goodrich’s recently completed Smith well, in Amite County, Miss., had initial daily production of 1,000 barrels of oil and 255,000 cubic feet of natural gas.

By contrast, Devon’s seven Tuscaloosa wells were producing the equivalent of 750 barrels of oil per day in March.

In order to get to the $300 million drilling budget Turnham envisions, Goodrich would have to bring in a partner or raise additional capital, he said.

A budget that big would mean that instead of one drilling rig, Goodrich could run two or three. Ultimately, Goodrich wants to have six or seven rigs working in the Tuscaloosa Marine Shale, but the company will have to build up to that.

Amelia Resources LLC President Kirk Barrell, who authors the Tuscaloosa Trend blog, called Goodrich’s acquisition “a brilliant, strategic move.”

Devon’s approach, on the other hand, he described as “baffling.”

Oklahoma City-based Devon spent about $50 million to acquire its leases in the Tuscaloosa. Devon probably spent about $17 million to drill each of its seven wells, or about $119 million in total, Barrell said.

“You see the price they sold at yesterday, it’s dumbfounding,” Barrell said. “It’s impossible to explain in my mind.”

China’s Sinopec bought a one-third interest in Devon’s acreage in January 2012, so it’s possible the Chinese firm helped cover some of the drilling costs. Even so, Goodrich picked up a $170 million project for a fraction of that investment.

Turnham said Goodrich was excited about the acquisition and the production from Goodrich’s Smith well.

Barrell said Devon had two major problems:

Unlike Goodrich, Devon didn’t drill the horizontal sections of its wells in the most productive layer of the formation, which is 100 to 250 feet thick.
Devon also didn’t use as much proppant, which keeps the fractures open, as it should have.
In hydraulic fracturing, or fracking, drilling companies crack the rock formations underground to release oil or natural gas. The drillers use millions of gallons of water and a mixture of sand and chemicals to keep the cracks open.

Devon used anywhere from 91,600 pounds to 317,500 pounds of proppant for each section of well fracked. Encana, which has about 300,000 acres in the Tuscaloosa, has used up to 1 million pounds of proppant per stage, while Goodrich used 453,556 pounds per stage in its Crosby well.

Don Briggs, president of the Louisiana Oil and Gas Association, said the Tuscaloosa is “a very mushy shale.”

When a driller fracked the Haynesville, it was like cracking slate. But in the Tuscaloosa, the rock is less brittle and the fractures tend to close.

Turnham said Goodrich has been able to accelerate the learning curve by applying the expertise it gained from the Eagle Ford Shale, an oil formation in Texas roughly the same geologic age as the Tuscaloosa, and in the Haynesville, where wells are drilled to similar depths — 11,000 to 13,000 feet.

In the Tuscaloosa, some of the clays swell when the fluid hits, acting more like a sponge, Turnham said. It’s more difficult to fracture the rock. Even if it fractures, the cracks want to close. So it’s important to figure out what to pump, how to pump it and how to prevent the clays from expanding.

Turnham said Goodrich is working to reduce its well costs to about $10 million per well. The firm’s Smith well cost $13 million to drill.

It took 41 days to drill the Smith well, and it costs $100,000 a day to lease a drilling rig. Goodrich expects to reduce drilling time to 30 days, which would save $1 million. The company also plans to frack multiple wells at the same time and to use pad drilling, where multiple wells can be drilled from the same site.

Once the play becomes more successful, all the service companies come in and that helps drive down costs.

Turnham expects other energy companies, including the majors, to move into the Tuscaloosa.

“The play just looks like too much potential here. And, of course, you get high oil prices, like Louisiana sweet,” Turnham said.

Louisiana light sweet crude is trading at about $7 more per barrel than the benchmark West Texas Intermediate. In addition, the state allows energy companies to delay paying royalties until they recover the cost of the well or for two years, whichever is shorter.

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Permalink Reply by al raptoria on October 7, 2013 at 3:09pm

Hi Chris, several times a week I get Stock bulletins pitching new and improved and cheap and environmentally sound ways to drill, to access deep oil, etc...could be pitching  pipedreams or maybe it really is just a matter of time. It makes sense that after throwing money at mineral rights owners a few years ago - all my neighbors for instance, and they are in that "oil only" area, that now the gas/oil companies need a quick fix, or at least the fastest way to recoup some of their money and volatile gas windows with little refining needed may get them their juice back, placate their shareholders, and raise more investment money for coming back and going after the oil. Oil still trades at over $100 while gas is around $3.63! AND we are headed for a glut of that...so tell me somebody please - why is oil devalued and wet gas hyped? Can't help but think it has to do with speed and ease and that the best waits for last.

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Permalink Reply by James Vanderink on October 7, 2013 at 3:12pm

Ask Jerry what he's doing in Rockeby locks/ Blue Rock.

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Permalink Reply by al raptoria on October 7, 2013 at 3:24pm

Talkin' to me? Got no idea who or what yer talkin' about -  but will look up a "Jerry: in Members...just in case....

Thanks...

....back again...we have 10 Jerrys as members...so I will await further details from any of them who care to comment.

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Permalink Reply by Craig Cooper on October 7, 2013 at 3:44pm

al,

While it may seem counter-intuitive, well production from the wet gas areas is more economic. IPs, overall production rates and production declines are all better in the wet gas areas. Physically, the combination creates a 'more energetic' reservoir system.

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Permalink Reply by al raptoria on October 7, 2013 at 4:09pm

Thanks Craig, makes cents...and dollars too!

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Permalink Reply by al raptoria on October 7, 2013 at 4:32pm

But how does ANYONE know EXACTLY where these areas are BEFORE drilling, and even after drilling if, according to member Ron D Jockefeller on  another thread, "Light oil is worth more than wet gas.  And a barrel of light oil is worth more than a barrel of NGLs.  Also, since the US is going to be producing way  too much NGLs for the petrochem industry for the next 12 to 18 months, NGL prices are going to be well below their historical correlation to Brent or WTI for a while Black v. Light v. Volatile are terms that have to do with the composition of  oil.  In general the longer the hydrocarbon chains the heavier the oil. Light oil without sulfur (aka sweet) is generally worth more since it produces higher value end products when refined.  Oddly, the
US refiners are mostly set up for intermediate and heavier crudes now
because that's what they expected their feedstocks to be... but now with all
this light stuff coming in we might see relatively lower price for light.  Good time to be a refiner.I agree it's too early to come up with  a sweet spot.  The producers haven't even figured out how long to rest their wells after fracking.  For the light  oil zone maybe it's 60 days, maybe 120, maybe somewhere in between.  We'll know in another 6 months or so."

Of course, that was posted more than 6 months ago...so how much more do we REALLY know??? Seems we all now know more about the different companies'  activities, skills and ethics than we know about the actual gas/oil production and potential!  (And what's a Brent or and WTI?) (Can't tell if I'm stupid or just tuckered out from the fracking fray...)

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Permalink Reply by Area Man on October 8, 2013 at 2:19am

It's not the price, it's the pressure and rate.  The oil window is updip/more shallow then wet gas, thus you have less pressure support.  Compounding the issue, oil is a heavier molecule and larger so it doesn't travel as quickly or efficiently as methane (ethane, pentane, pick your gas hydrocarbon).

It's pricey stuff if you can get it out of the ground, but it is much more challenging.

Hope that helps some.

Cheers,

-AreaMan

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