Baxter shale Wyoming
Cretaceous 2.19 MMcfd
Oil & Gas Journal / Dec. 8, 2008
Devon Energy Corp. started production at the 5-3 Horseshoe Basin Unit
well in the Vermillion Creek area of the Greater Green River basin in
Sweetwater County, Wyo. Output from Cretaceous Baxter shale
totaled 21.7 MMcf gas and 3,836 bbl of condensate in the first 6.5 days
on line, and the current rate is 2.19 MMcfd and 412 b/d of condensate,
said 50% working interest owner Kodiak Oil & Gas Corp., Denver. TD
is 13,534 ft. Three wells have been drilled, and Devon is
acquiring 25 sq miles of 3D seismic in the area. The outlook for 2009
is for horizontal drilling in the Baxter, said Kodiak.
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Jurassic
Haynesville/Bossier shale Texas East
December 8, OGJ.com
GMX Resources Inc., Oklahoma City, said its Callison-9H well
in Harrison County, Tex., stabilized at 7.7 MMcfd of gas on a 22/64-in.
choke with 5,200 psi flowing casing pressure from Jurassic
Haynesville/Bossier shale. The company ran an eight-stage frac in the
well’s 2,200-ft lateral, its shortest planned lateral in the play. GMX
has 100% working interest. GMX is drilling the Bosh-1l H and
Baldwin-I7 H wells and expects to spud a fourth well within 2 weeks.
The next 16 wells are expected to average 3,800-ft laterals and 11-12
frac stages. The company plans to drill 45 wells in 2009.
The Belin-1 well in the Hilltop area of the deep Bossier play has the
potential to be Gastar Exploration Ltd.’s best well to date in terms of
flow rate and reserves, the company said. Logs indicated 150 net ft of
pay in the middle and lower Bossier formations. TD is 18,800 ft.
The well’s three Lower Bossier pay zones have the highest measured
porosity, up to 25%, of any well drilled by Gastar in the play.
Belin- also encountered two middle Bossier sands, including the Lanier
sand, in a downdip location in a new fault block with indicated pay
based on log analysis. The well, to be on line within 30 days, is to be
completed in the two deepest zones first. The Lanier sand has
been shown to be productive in a downthrown fault block from the
Wildman Trust-3 well, where Lanier was recently recompleted at an
initial 21 MMcfd.
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Marcellus shale Pennsylvania
30 MMcfd -7 wells
December 8, OGJ.com
Range Resources Corp., Fort Worth, said seven wells totaling 30 MMcfd
from the Marcellus shale are connected to Pennsylvania’s first
large-scale gas processing plant, operated by MarkWest Energy Partners
LP. Range plans to begin flowing more wells as two more gas
processing plants are completed next year (OGJ Online, Oct. 22,
2008). The company plans to enter 2009 with three horizontal rigs
and boost that to six by the end of the year. It expects yearend 2009
production to reach anet 80-100 MMcfed.
Talisman Energy Inc., Calgary, deferred a five-well Marcellus shale
pilot in New York pending environmental and regulatory reviews and
shifted its focus to Pennsylvania. The company’s Fortuna Energy
Inc. unit holds almost 120,000 acres of state controlled land in
north-central Pennsylvania and is drilling a pilot in an area where it
owns 19,200 net acres prospective for development. It was completing
its first operated horizontal well this month. Talisman Energy’s
holding totals 640,000 net acres in both states in the emerging
overpressured Marcellus play. It estimates gas in place in the
Marcellus at 20-100 bcf/sq mile at 2,500-6,000 ft.
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America's Natural gas
trade $5-6/MMbtu to 2013 WoodMac:
OGJ.com 12/8/08
US natural gas is expected to trade at $5-6/MMbtu over
the next 5 years, said an executive of Wood Mackenzie Ltd., Edinburgh,
at a recent energy forum sponsored by that firm in Houston.
Jen Snyder, head of WoodMac North American Gas Research, told forum
participants that the industry’s successful development of shale gas
plays has positioned the market for “significant potential
over-supply.” Snyder rejects a popular theory that gas prices will
settle eventually at the marginal cost of the most expensive shale
plays. That represents “a mistaken reading of the current and future
environment,” she said. “Simply stated, there is no requirement for the
rapid near-to-midterm development of some of the more expensive or
challenging shales such as the Marcellus or Horn River; the market can
be adequately supplied without these volumes.”
She sees “sufficient volumes available at a development break-even
price of $5.50/MMbtu or below.” That conclusion is based on declining
demand due to “a prolonged recession” to fourth-quarter 2010, new wind
and coal-fired capacity coming online to generate electricity, and “a
significant drop in drilling activity” because of a lower commodity
price. “We have also factored in the positive impact on break-even
costs due to cost reductions associated with this drilling slow-down
and continued optimization of drilling solutions at those plays that
will continue to be aggressively developed,” Snyder said.
Furthermore, she said, “The results of our Global Gas Optimization
Model point to significant import volumes of LNG over the next few
years, despite the recent growth in unconventionals.” Existing offtake
agreements for some suppliers “make diversions from North America
unlikely,” Snyder said. “In addition, other suppliers with flexible LNG
will want to avoid jeopardizing long-term contract prices in Europe and
Asia, through a further weakening of spot prices in these areas.” Qatar
in particular will likely direct some of its new LNG volumes to the US
market “where there are no long-term contract implications and a large
and liquid market to absorb the volumes,” Snyder said.
WoodMac’s projected gas price of $5-6/MMbtu would not be a floor price,
as near-term market weakness could force prices below that range,
Snyder said.
“Our near-term forecast is predicated on a normal winter. While a
severe winter could tighten up the market and provide some near-term
support, equally a mild winter could exacerbate the current position of
over-supply and lead to prices into the $4/MMbtu range in the near
term,” Snyder added. “We have also assumed that gas demand benefits
from a 1 .5 bcfd switch from coal to gas-fired power generation. If
this fails to materialize due to collapsing coal prices, this would
further add to short-term price weakness.”
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Sakhalin Energy
Starts Year-Round Crude Oil Exports
Dec. 12, 2008 By Torrey Clark From
Bloomberg
OAO Gazprom’s Sakhalin Energy venture began year-round oil exports
today and plans to start producing liquefied natural gas in “the next
few weeks” after building pipelines to the southern tip of the Pacific
island.
The project will use two tankers, the Governor Farkhutdinov and
Sakhalin Island, to export oil this season, Sakhalin Energy said today
in an e-mailed statement.
The $22 billion project had been slated to begin year-round oil exports
in 2007 and LNG exports in the second half of this year. Royal Dutch
Shell Plc, Europe’s biggest oil producer, agreed to cede control of
Sakhalin-2 to Gazprom two years ago after months of pressure from
environmental regulators, who threatened to shut down the project.
Gazprom owns 50 percent plus one share of Sakhalin Energy Co. Shell has
27.5 percent, Mitsui & Co. holds 12.5 percent and Mitsubishi Corp.
has 10 percent. Much of the LNG will be exported to Japan, the world’s
biggest buyer of the fuel. LNG is natural gas chilled to liquid form to
aid transportation and storage by ocean-going tanker.
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U.S. energy stocks
recover but Gas Oil Low
Reuters, Friday December 12 2008 By Anna Driver HOUSTON, Dec 12 Reuters
U.S. energy company shares have rebounded from their lowest levels in
years, easily outperforming the market, but hopes for more gains may be
dashed as the sluggish global economy threatens to keep oil and gas
prices weak. The Standard & Poor's index of energy companies
has climbed 13 percent since hitting an intraday year-low on Oct. 10,
helped by a jump in crude oil prices and the sector's low valuations.
In the same period, the broader Standard & Poor's 500 index fell 4
percent. The S&P energy index, which includes companies like
Exxon Mobil Corp, Chevron Corp and oilfield services giant Schlumberger
Ltd, has also done better than crude oil futures, which have tumbled
more than 40 percent since October.
But analysts and investors caution that the stocks' gains may not
continue in coming weeks as commodity prices stay under pressure. The
global economic crisis is expected to crimp demand for crude oil, and
growing supplies of natural gas in the United States should weigh on
prices.
OPEC is expected to announce production cuts when it meets next
Wednesday, but investors should not pin their hopes on that arresting
crude's slide. "From my experience, when OPEC tries its hardest
to stop oil prices from falling, that's when they have the least amount
of control," said Ted Parrish, principal at Henssler Financial Group
who helps manage $1.3 billion in assets.
Others noted that history shows OPEC has needed to make several
production cuts before crude oil prices find a floor. Goldman
Sachs on Thursday lowered its 2009 oil price outlook to $45 a barrel
from $75 and warned it may fall as low as $30, citing deterioration in
global oil demand. Even so, the bank said it sees "a growing
number of signs that the oil markets may have entered the bottoming
phase of the cycle." Goldman suggested investors take a defensive
approach to investing; its top picks include Chevron, pipeline operator
Oneok Inc and Royal Dutch Shell.
Oilfield services firms, which face exposure to project cancellations
and a falling rig count, are especially vulnerable to weakness in oil
and gas prices. "These companies do extremely well when prices
are in their favor," Henssler's Parrish said. "But you are going to see
projects canceled if oil prices stay where they are."
SUPPLY LOOMS
Independent energy companies that have a big exposure to natural gas
production may also struggle as economic woes bite into demand and
supplies build. "I don't think it's going to be a great year for
natural gas," said Ray Deacon, senior analyst at Pritchard Capital
Partners. "I don't see any kind of near-term recovery." A weak
economy is expected to shave 1 billion to 3 billion cubic feet per day
off U.S. natural gas demand in 2009. The country uses 63 billion cubic
feet every day.
On Friday, Barclays Capital cut its 2009 earnings-per-share estimates
for large-cap independent oil and gas producers by 41 percent, citing
expectations for a weak gas market. "While we believe long-term
investors may be rewarded for holding exploration and production shares
today, we think that E&P shares are likely to be under pressure for
the next several months as evidence of a gas oversupply accumulates,"
Barclays' Thomas Driscoll wrote in a note to clients.
Natural gas prices may fall
below $4 to $5 per thousand cubic feet by mid-winter, Barclays said.
On Friday, natural gas futures traded on the New York
Mercantile Exchange were down 1 percent at $5.53 per million British
thermal units. Crude oil futures slid 3.5 percent to $46.28 per
barrel. Exploration and production companies best suited to
weather a downturn include Apache Corp and Noble Energy Inc, Barclays
said.
Adding to the build-up in natural gas supplies, U.S. liquefied natural
gas imports may rise in 2009 as the global credit crunch dents demand
elsewhere for the fuel. To cope with natural gas price declines,
a number of U.S. energy companies have scaled back drilling budgets and
idled rigs, but Barclays said more cuts are needed to balance supply
and demand. (Editing by John Wallace)
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Energy fuels widening
U.S., Canadian economic relationship
December 13, 2008 Houston Business Journal
CALGARY, Alberta
Walk into the downtown Calgary office of U.S. Consul General Tom
Huffaker, and he’ll show you his well-worn plastic bag of
bitumen. Huffaker, the U.S. government’s eyes and ears spanning a
huge chunk of Canadian real estate covering two western provinces plus
the expansive Northwest Territories, likes to pass around the bag
containing several of the spongy, black chunks — made up of oil, sand,
water and clay — as an icebreaker.
Up close, the tar-like bitumen may not seem like anything of particular
value, but when complex, costly processing methods are applied, it
becomes liquid gold. The resulting heavy oil extracted from the bitumen
deposits in the oil sands around Fort McMurray in northeastern Alberta
represents a major part of the future strategy of the United States to
rely less on oil imported from Saudi Arabia or Venezuela.
In fact, Canada is already the No. 1 source of oil shipped to the U.S.,
accounting for nearly 20 percent of imports. Nearly 2 million barrels
of crude are shipped from Canada to the U.S. each day, making up the
majority of the total 3 million barrels a day of Canadian production.
Only Saudi Arabia has more proven oil reserves under the ground than
Canada.
Huffaker is happy to relay these types of facts to American visitors.
He’ll also mention that, as the largest trading partner with the U.S.,
Canada ships huge volumes of natural gas and electric power south of
the border each day. And millions of U.S. light bulbs run every day on
nuclear power that owes its source to the province of Saskatchewan, the
world’s largest uranium producer.
It’s all part of one of the most extensive trading relationships in the
world. In 2007, Canada imported $220 billion worth of goods from the
U.S. — its biggest trading partner — while exporting $356 billion worth
of goods into the U.S., which works out to 80 percent of Canada’s total
exports. The single bridge connecting Windsor, Ontario, with Detroit
carries more goods back and forth each year than all of the goods
shipped between Japan and the U.S.
Fueled by the 1994 North American Free Trade Agreement, Canada-U.S.
trade now directly supports 7.1 million jobs, including 521,750 jobs in
Texas. Some $12 billion in Texas exports headed north to Canada in 2007
— including $297 million worth of exports from Houston.
“Even if it’s our biggest trade relationship that doesn’t mean it
can’t, and will, get bigger,” says Huffaker. “People often make a big
issue about the future of that relationship when there’s going to be a
new president or energy secretary, but there is always this bedrock
relationship, and no matter who holds the big jobs on either side of
the border, they know how important the relationship is.”
Huffaker helps U.S. companies that have recently relocated to his
region of Canada deal with the governmental complexities of undertaking
such a major step, and also might help stickhandle some U.S. regulatory
issues for Canadian pipeline operators teaming up with U.S. partners to
build projects south of the border.
“The biggest issue we deal with is the whole Canada-U.S. connection
related to energy security, climate change and the oil sands. The U.S.
government is pro-oil sands, but local decisions on environmental
standards and carbon footprints are for Albertans and Canadians to
make,” he says.
During the run-up to the hotly contested U.S. presidential election,
energy was certainly on the minds of Americans when oil hit its peak of
$147 a barrel in the summer. Although both Barack Obama and John McCain
mentioned repeatedly about the need to wean the U.S. from its
dependence on foreign oil, Huffaker and Canadian officials were
confident that Canadian oil was excluded from that discussion.
“I’m pretty sure that when President-elect Obama is talking about
foreign crude, he’s really talking about offshore crude, and not
throwing in Canadian crude,” says Dave Collyer, president of the
Canadian Association of Petroleum Producers.
“Naturally, we’re always concerned when people talk about restricting
access to markets. But (Obama’s) clarifications about what he was
talking about with foreign oil were certainly helpful.”
Canadian Prime Minister Stephen Harper was quick off the mark, calling
for a new climate change pact to be negotiated with the U.S. within a
day of Obama’s Nov. 4 election victory — seeking to quell what was seen
as a rising tide of opposition within the Obama camp about so-called
“dirty oil,” in reference to Alberta’s vast oil sands deposits — that
are vital to the U.S. energy supply. Obama pledged during the campaign
to cut greenhouse gas emissions to 1990 levels by 2020, about a 15
percent reduction.
Greenhouse gas emissions related to oil sand production are about 15
percent higher than for conventional crude, according to Collyer.
While both countries are looking at setting up new market-based
emission trading systems, Collyer expects that the interdependence of
the two countries will push both sides toward joint discussions. Both
countries seem headed toward the goal of creating a more streamlined
national policy rather than depend on the potpourri of emissions plans
adopted by individual Canadian provinces or U.S. states.
California, for example, has passed regulations forcing gasoline
marketers to reduce carbon emissions traced all the way back to their
production sources.
“At the end of the day, Canada and the U.S. want their own policies on
this issue, but collaboration is important,” Collyer says. “It makes
sense to look at environmental policy within the context of energy
policies, and whether a cap and trade system is really the right
framework. If Canada and the U.S. can come to terms on a policy that
makes senses for this continent, we’ll be in better shape to negotiate
internationally.”
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Ghana pipeline gets
first Nigerian gas
12.13.08, By Kwasi Kpodo ACCRA, Dec 13 Reuters
A new West African gas pipeline has begun pumping Nigerian gas to
Ghana, where new gas-fired power generation should start up as early as
January, companies involved in the project said. The $620
million, 678 km (420 mile) pipeline has been built to transport natural
gas from Nigeria's Niger Delta to Benin, Togo and Ghana to help ease
chronic power shortages.
Ghana's Volta River Authority (VRA) power utility said in a statement
late on Friday that the pipeline had been successfully filled and shut
in, and the company was talking to suppliers to ensure continued flow
once commissioning was completed.
VRA, which produces most of Ghana's electricity from the huge Volta
dam, said on its website www.vra.com that it is increasing capacity at
its Takoradi thermal plant to 660 MW from 550 MW, and switching from
liquid fuel to gas to cut costs. Frequent power cuts, especially in
2006, forced rolling blackouts across Ghana and reduced mining output
from Africa's second biggest gold producer.
'This will ensure a reduction in the cost of production, as natural gas
is cheaper than light crude oil that has been the source of fuel for
the Takoradi plant since its construction 10 years ago,' VRA spokesman
Kofi Asante Okai said in Friday's statement.
Comment On This Story
Research dating from 2005 indicated switching to gas could cut fuel
costs by around one-third, VRA's acting general manager for thermal
generation, Richard Badger, told Reuters.
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Alaska's Southcentral gas situation is grim
December 14, 2008 By Tim Bradner Alaska Journal of
Commerce
Southcentral Alaska's natural gas situation is getting grim. The large
producing fields in the region are being depleted faster than
expected. While there is still plenty of gas left in producing
gas fields, producing companies and utilities are concerned about the
“deliverability” of the fields, or the capability of the aging wells to
produce enough on cold winter days to meet peak demands.
“Gas deliverability from the four largest fields in the Cook Inlet
Basin has declined significantly in the last three years,” Steve
Wright, Chevron Corp.'s Alaska asset manager, told the Resource
Development Council Nov. 19. “These four fields - Beluga River, North
Cook Inlet, McArthur River field and Kenai field - were capable of
delivering up to 14 billion cubic feet per month in January 2004. At
present, they are capable of producing only 9 billion cubic feet per
month.”
The four fields produce about 65 percent of the natural gas production
in Southcentral Alaska. The concern over deliverability was a major
factor in Chevron's decision to reduce the amount of gas it will supply
in its contracts with Enstar Natural Gas Co. from 2012 to 2016. “We
could not document that we would have adequate deliverability to have
met this commitment,” Wright said.
The heat and power in Southcentral Alaska communities won't get turned
off, however. ConocoPhillips and Marathon Oil, the owners of the
liquefied natural gas plant near Kenai, have pledged to backstop
utilities if gas deliverability is insufficient on cold days.
Still, the underlying problem of declining reserves is getting worse,
and exploration results in recent years have been modest. “Gas
exploration has not been successful. Chevron has operated six
exploration wells in recent years and have had only modest success,”
Wright told the RDC council. There is good potential in the
region, but the problem is that many areas with prospective geology
have substantial surface occupancy issues, he said, which limits
explorers' access.
Production has actually dipped below what the state Department of
Natural Resources has estimated would be possible from remaining proved
gas reserves in the Cook Inlet Basin, he said.
The industry isn't sitting on its hands, however. Chevron and other
Cook Inlet operators are making substantial investments. Two years ago
Chevron announced a $400 million program to refurbish aging oil
production platforms in Cook Inlet and to stimulate new gas production.
The company is carrying out that program, Wright said.
Marathon and ConocoPhillips have made separate commitments to drill new
gas wells in an agreement with the state related to a two-year
extension of a liquefied natural gas export license for the Kenai-area
plant the two companies own. “Our hope is that new drilling in
the Beluga and Ninilchik fields will stem the decline, but we see no
scenario where the decline is eliminated,” Wright said.
Chevron itself has spent $200 million over the last years in its new
drilling program, which include oil as well as gas. Chevron has
invested in projects in seven gas fields and two oil fields.
Results of the drilling are generally positive, but there were
disappointments as well, Wright said. “A few of our wells far
exceeded expectations, some came close to what we had forecast, but a
couple were expensive but poor producers,” he told the RDC. “There is a
lot of stratigraphic variability in Cook Inlet. The risks and
uncertainties there are not average.” The company still expects
to spend $100 million to $200 million over the next three to five years
on projects, but plans are always subject to change. Given the downward
shift in oil prices, “we are currently reassessing our opportunity
catalogue,” Wright said.
Natural gas projects in the last year have included two new gas
development wells in the Happy Valley gas field on the Kenai Peninsula,
the installation of a new production pad and the testing of a new
“fracture” technology to stimulate production, and three new gas wells
and a compressor to boost deliverability of gas in the Ninikchik gas
field, where Chevron owns 40 percent (Marathon Oil is the majority
owner, at 60 percent, and operator). Other projects included two new
gas wells and a workover in the Beluga River gas field, and two new
production wells and the addition of compressor capability on the
Steelhead platform, which produces gas.
On the oil side, Chevron has drilled two new wells in the Granite Point
field from the Anna platform. These wells did not meet expectations,
Wright said. Chevron also drilled one new well and two well maintenance
jobs in the Swanson River oil field, and performed six well maintenance
jobs in the McArthur River field.
“Gas-lift” wells, which use natural gas to lift crude oil up producing
wells, were also converted to down-hole electric pumps to bring the oil
up. This has the effect of freeing up gas supplies, Wright said.
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