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Many emerging US fields now commonly considered part of the “shale” boom are not really shale at all, but rather tight oil such as in the Permian Basin or even conventional fields made un-conventional by modern techniques such as horizontal drilling, multistage fracturing that helps draw more oil from rocks and long laterals—the horizontal leg of a well—to enhance their economics.

“Shale is very fine grained…rock,” containing silica, Peng Li, petroleum geologist at the Arkansas Geological Survey, said. According to other sources, it also contains clay and even quartz. On the other hand, other plays being developed unconventionally are carbonates (such as the Permian Basin), sandstone, siltstones, limestone or even mudstone. “The difference is in the type of rock,” Li said.

While the Eagle Ford Shale in South Texas and Bakken Shale in North Dakota/Montana are two of the biggest shale oil plays, wildcatters continue trying to smoke out the next big oil find. There, shale hasn’t been the draw, but rather conventional fields some of which have produced modestly for years.

Company managers are now talking up older fields such as the Woodbine in East Texas, the Brown Dense in Louisiana/Arkansas and the Tuscaloosa Marine Shale in Louisiana/Mississippi as potential up-and-comers.

The Woodbine consists of sandstone and siltstone rocks, located at about 7,400-9,400 foot depths across several counties north of Houston. The formation sits below the Eagle Ford horizon, which some operators say is also potentially productive in that area. For that reason, many operators call it the Eaglebine play.

But according to oil companies, the Eagle Ford zone there is shallower than in south Texas where production is galloping. Eaglebine wells have approached initial production rates of a solid 1,000 b/d of equivalent oil in some cases; small operator Crimson Exploration, for instance, has seen rates above 1,200 boe/d. The company has said other zones may also be productive.

Global Hunter Securities cited a Devon Energy well that debuted at 936 boe/d from the Georgetown formation, while tiny Navidad Resources has vertically commingled the Buda, Georgetown and Glen Rose formations and “has produced 135,000 boe in a year,” or about 370 boe/d.

The Woodbine also has favorable well costs around $5.5 million versus $6-$7 million in the South Texas Eagle Ford, companies have said.

- The Brown Dense play is an old play made up of carbonate mudstone found at roughly 8,000-12,000 feet depths. Southwestern Energy, which pioneered the Fayetteville Shale, is a leader in this play also. It has drilled six wells, all but one in Louisiana.

One of the wells came in at over 1,000 boe/d of output that included 421 b/d of oil. The company is targeting sections 300-500 feet thick.

CEO Steve Mueller said in an August company call that its Brown Dense wells could cost $10-$12 million, topping initial $8 million estimates due to higher-than-expected well pressures. “When you start looking at how that works out on the economics, I think [a] 500-barrel-a-day range on the oil-only side still makes that work,” Mueller said.

- The Tuscaloosa Marine Shale is a shale, found between 10,000 to more than 16,000 foot depths with thickness varying from between 500 feet in Louisiana to over 800 feet in Mississippi, according to a report released earlier this year by David Dismukes, associate executive director of the Center for Energy Studies at Louisiana State University.

Tuscaloosa operator Devon Energy so far has drilled three wells in the play; the first averaged just shy of 300 b/d and the second, 670 b/d—an improvement, which company officials say they hope to sustain. Because of the depth, wells are costly at $12 million to the mid-teens. “Reducing costs and improving well performance over time are keys to making this play economic,” said David Hager, Devon executive vice president of E&P.

- Then there is an apparent one-man shop in an acreage spread west of Houston called the Navarro/Midway field. Said GHS in a recent report, “nobody else is leasing here, but [Halcon Resources CEO Floyd Wilson] liked this play so much he leased it personally” after selling his former company, Petrohawk Energy, last year. Petrohawk in 2008 pioneered the Eagle Ford Shale; BHP Billiton gobbled up the company for $15 billion.

The Navarro/Midway are two formations; Halcon has targeted both in vertical wells which require multistage fracturing to make them economic, Wilson said at a recent energy conference. The company has drilled two wells there; both should unearth a mix of oil, natural gas and gas liquids, he said.

Navarro is the deeper zone that may hold more gas and less oil; Midway has “a lot more oil and a little less gas,” said Wilson. “I’m expecting big numbers.”

 

original article

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A bit of a gush in oil returns is putting the brakes on gas production Goldman Sachs GS -0.10% analysts wrote in a research note.

Natural gas production in the U.S. has soared since 2005 as drilling companies began to use new technology to exploit the country’s vast reserves of shale gas.

The gas boom saw prices slump to their lowest in decades, even as oil prices soared to near record highs.

Not surprisingly, savvy drillers have been quick to shift gear and target areas richer in the more profitable commodity.

Goldman cites data compiled by Baker Hughes BHI -0.04% that shows the number of rigs drilling in the Haynesville shale gas formation in Louisiana and Texas have plummeted since the beginning of last year to less than 50 rigs from more than 150. Meanwhile, the number of rigs in the neighboring and liquids-rich Eagle Ford have soared in the same period from just under 100 to nearly 250.

Unlike in Haynesville, drillers in Eagle Ford can choose to drill for gas or oil. Given the current economics, many have chosen to focus on the oilier parts of the area, a move that Goldman estimates has meant gas production from the formation is currently half what it might be.

According to Goldman, moving a rig from the Haynesville to Eagle Ford cuts the gas production from the rig in half if it moves to an area of the formation that is rich in natural gas and by as much as 80% if it moves to a more oily area.

“Consequently, Eagle Ford natural gas production growth is not likely to be strong enough to compensate for declining production in Haynesville, and, on net, we expect the migration of rigs into Eagle Ford to slow US natural gas production,” says the bank.

To change this equation would require natural gas prices to recover to $5.30 a million British thermal units, Goldman says. With Henry Hub futures prices hovering around $2.80 a million British thermal units, we have a way to go yet.

 

original article

New front-month under Wednesday’s 5-1/2 month high

* Hot weather still on tap in six to 10-day outlooks

* Recent storage data, drilling rig data supportive

* Coming Up: EIA natgas storage data Thursday

 

By Eileen Houlihan

NEW YORK, June 28 (Reuters) – U.S. natural gas futures were

little changed in early trade Thursday, with traders awaiting

more direction from weekly inventory data due out later this

morning.

On Wednesday nearby futures rose to a 5-1/2 month spot chart

high amid forecasts for more hot weather in what has become a

scorching start to summer.

Continued widespread heat is expected over most of the

nation for at least the next two weeks.

In addition, Tropical Storm Debby knocked out about 5

billion cubic feet of offshore Gulf of Mexico production over

the weekend, but no serious damage to facilities was reported.

Most traders and analysts expect this week’s storage report

from the U.S. Energy Information Administration to show a build

of about 52 bcf when it is released today at about 10:30 a.m.

EDT (1430 GMT), a Reuters poll showed.

Last year stocks rose an adjusted 84 bcf for that week and

on average for the past five years have gained 85 bcf that week.

If the build comes in near the Reuters poll number, it will

be below average for a ninth straight week, a factor that has

helped raised expectations that record-high inventories will be

trimmed to manageable levels in the 21 weeks before winter

withdrawals begin.

As of 9:28 a.m. EDT (1328 GMT), new front-month August

natural gas futures on the New York Mercantile Exchange

were at $2.80 per million British thermal units, up 0.2 cent.

The July contract traded as high as $2.946, its highest mark

since early January, before expiring less than 1 cent higher for

the day.

Some traders remained concerned that a move close to $3

would again reduce the appeal of gas over coal for power

generation.

Since posting a 10-year low of $1.902 twice in late April,

nearby futures are up about 47 percent on signs that record

production was finally slowing and demand picking up as more

electric utilities switched from coal to gas.

 

ANOTHER LIGHT BUILD BUT STORAGE STILL AT RECORD

Last week’s EIA storage report showed total domestic gas

inventories rose by 62 bcf to 3.006 trillion cubic feet.

 

The build trimmed the surplus to last year to 680 bcf, or 29

percent, and sliced the excess versus the five-year average to

641 bcf, or 27 percent.

(Storage graphic: link.reuters.com/mup44s)

But inventories remained at record highs for this time of

year, topping the 3 tcf mark at the earliest on record,

according to weekly and monthly EIA data going back more than 35

years.

Total storage is already 73 percent full and hovering at a

level not normally reached until late August. Producing-region

stocks are at 83 percent of capacity.

Concerns remained that the storage overhang could still

drive prices to new lows this summer as storage caverns fill.

The storage surplus to last year will have to be cut by at

least another 435 bcf to avoid breaching the government’s

4.1-tcf estimate of total capacity.

Stocks peaked last year in November at a record 3.852 tcf.

The EIA expects gas storage to climb to a record 4.015 tcf by

the end of October.

 

DEMAND UP, PRODUCTION GROWTH SLOWS

Gas demand picked up sharply this year as spring prices hit

10-year lows, prompting many utilities to use more gas-fired

generators to produce power.

Baker Hughes data last week showed the gas-directed rig

count fell by 21 to a 13-year low of 541, its eighth drop in

nine weeks.

(Rig graphic: r.reuters.com/dyb62s)

A 42 percent drop in dry gas drilling in the last eight

months has raised expectations that producers are finally

getting serious about curbing record supplies.

But the producer shift in focus away from dry gas to

higher-value shale oil and shale gas liquid plays still produces

plenty of associated gas that ends up in the market after

processing. That has slowed the overall drop in dry gas output.

While EIA expects 2012 marketed gas production to average a

record high 68.47 bcf per day, up 3.4 percent from last year, it

sees demand, driven by strong gains in the electric power

sector, rising 4.1 percent.

 

MORE FUNDAMENTALS

The National Weather Service’s 6- to 10-day outlook issued

on Wednesday again called for above-normal readings for most of

the nation, with normal or below-normal readings only in the

West and Florida.

Nuclear power plant outages were running at about 9,000

megawatts, or 9 percent, on Thursday, up from 8,400 MW a year

ago and a five-year outage rate of just 5,900 MW.

 

The U.S. National Hurricane Center was monitoring the

remnants of Tropical Storm Debby, west-northwest of Bermuda, and

a tropical wave well east of the Windward Islands. No other

storm formation was expected over the next 48 hours. The

Atlantic hurricane season runs from June 1 through Nov. 30.

 

The latest government statistics show the Gulf of Mexico

accounts for 6 percent of U.S. gas production and just over 20

percent of U.S. oil production.

Original Article

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The U.S. has been trying to wean itself off imported crude since the 1973 oil embargo, but America’s love for cars and gasoline to fuel them has made that difficult – until now.

In a sign that a rise in domestic oil production is actually having an impact, Valero Energy Corp.  VLO 0.01% will stop importing light, sweet crude oil  for its big Gulf of Mexico refineries by the end of 2013, about two years earlier than planned. It’ll continue to import much of its heavier grade crudes from Canada and elsewhere.

In a fresh sign of the trend, the U.S. imported 763,000 barrels of oil a day of light, sweet crude in the last six months, much lower than the import rate of 952,000 barrels a day for all of 2011.

Valero CEO Bill Klesse said the company expects significant growth in U.S. shale crude  production to make its way to the Gulf of Mexico via pipeline, rail and barge.

All told, as energy companies build up production in the Eagle Ford of Texas, the Bakken of North Dakota, and many other areas, imports of light, sweet crude will continue to dip. That local production will provide a cost advantage to Gulf Coast refiners against imported crude.

Valero sees the light, sweet import spigot getting turned off entirely in the Gulf region stretching from Texas to Alabama by 2013 or 2104, according to Valero’s presentation at the Citi Global Energy Conference on June 6.  With a big chunk of U.S. refining capacity based on the Gulf Coast, that could make a difference.

 

original article