Diesel = one-fifth of
all U.S. highway fuel demand
WINTER 2008 API INSIGHT
Even before the planned expansions are completed, U.S.
refiners are producing record amounts of diesel to meet growing demand
and capitalize on high diesel margins. Since 2005, diesel prices have
been higher than gasoline prices. According to the ETA, U.S. refiners
increased their yields of diesel fuel to the highest levels since the
agency began keeping records in 1993. ETA analyst Joanne Shore says
this summer’s performance underlined the industry’s determination to
crank out more diesel.
“High distillate margins in the summer of 2008 provided refiners with
incentives to increase distillate production. Gasoline margins were
sometimes negative, but distillate margins were very high. Once it
became evident that this high-margin distillate picture was going to
last some time, refiners began focusing on shifting to higher
distillate yields at the expense of gasoline, which was in surplus
supply,” Shore says.
“With the planned hydrocracking capacity, the U.S. refiners might not
need to do much more to satisfy U.S. distillate needs and even increase
exports of distillate.”
Shore says the longer-term fundamental picture seems to justify
refiners taking steps to increase distillate production versus gasoline
but the level of investment that will achieve a favorable return is
less clear, She says the ETA sees a significant shift in demand for
petroleum-based gasoline versus distillate over the next 15 years
because of recent U.S. legislation.
“While still not the shift that Europe has seen, U.S. refiners will be
facing a significant change in product mix from the refinery that will
impact investments,” Shore says. She noted that the ETA is predicting
that overall oil demand is not expected to grow much over the next 30
years — perhaps less than one-half percent per year on an annual
average while distillate demand may still grow fairly strongly as
gasoline demand declines.
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 Barnett shale-gas
resource largest gas field in the US
Williams Exploration and Production Oil & Gas Journal Dec. 15, 2008
Williams Production Gulf Coast Co. is simultaneously fracturing wells
in North Texas to improve production rates.
Since 2005, Williams has drilled more than 100 horizontal wells in the
Barnett shale, an unconventional gas reservoir that underlies a
19-county area in the Fort Worth basin. Slick-water fracturing is the
primary technique used to hydraulically fracture the wells.
Recently, Williams and several other operators tried fracturing two or
more adjacent wells simultaneously with the goal of exposing the shale
to more pressure and produce a more complex web of fractures, thereby
improving the initial rates and reserves. Simultaneous fracturing or
“simo-frac” technique is expensive and requires much more planning,
coordination, and logistics as well as a larger surface location than
single frac jobs.
Case history of follows: sequential and simultaneous fracturing
of four similarly drilled and completed horizontal azimuth wells in
eastern Parker County, Tex. All four wells were stimulated with near
identical fracture treatments. Three wells with sequential and
simultaneous fracturing had initial production (IP) of 3.3-3.5 MMscfd
with 30-day averages ranging from 2.1-2.9 MMscfd. The fourth well was a
single offset, horizontal well drilled with effective lateral length of
2,400 ft, located less than a quarter mile north of the first three
wells. But Well D had significantly lower IP of 2.3 MMscfd and 30-day
average production of 1.2 MMscfd.
The initial comparative test results are very encouraging and indicate
that the sequential and simultaneous fracturing creates a more complex
fracture network, which results in significantly improved well
production.
Williams continues to evaluate the benefit of simultaneous fracturing
and has done more simo-frac jobs in other counties with good results.
Due to surface and lease constraints, many of the simo-frac jobs are
performed in wells that are drilled from the same dual pad and have
well spacing on the order of 500-700 ft.
Barnett activity
The Barnett shale has evolved into the preeminent shale-gas resource
plays in the US and is now considered by many as the largest onshore
natural gas field in the US. The estimated productive part of the
formation covers 5,000 sq miles, encompassing 19 counties.
According to the latest figures published by the Texas Railroad
Commission (R.RC) in June 2008, there are more than 7,700 producing
wells and 185 active operators in the Barnett shale, holding permits
for more than 4,500 additional wells.
Production from Barnett shale currently exceeds 3.7 bcfd, accounting
for more than 15% of Texas gas production. The Barnett shale has
produced more than 3.8 tcf natural gas since 2000.
‘Simo-fracs’
Simultaneous fracturing of paired, offset wells is one of the recent
trends in Barnett fracturing and is being increasingly used by many
operators. In this technique, two or more adjacent wells that are
roughly parallel to each other are fractured simultaneously The goal is
to expose the shale to more pressure and produce a more complex,
three-dimensional web of fractures, increasing the density and surface
area of the hydraulic fracture network. The drainage area of each of
the wells is enhanced as the frac fluid is pushed into the space
between the two wells that would not have been fractured if the
operator had stimulated only well. Simo-fracs are expensive and require
more coordination, logistical work, and a larger footprint than a
single frac job. At the same time, they are cost-effective
because the frac equipment is utilized more efficiently; two wells are
completed in 1 week instead of 2 weeks.
Initially, simultaneous fracturing in the Barnett involved dual fracs,
involving two horizontal wells close to each other. Today, operators
are experimenting with triple simultaneous fracs or even quad-fracs.
Case history
Williams used three horizontal wells in eastern Parker County to
experiment with sequential and simultaneous fracturing. We1l A, with a
2,200-ft long lateral, was drilled from a separate pad. Two other
wells, Well B and Well C, with lateral lengths 1,900-2,000 ft, were
drilled from a single pad. Wells A and C are spaced 900-ft apart at the
heel and about 500 ft at the toe.
Williams drilled a fourth, stand-alone horizontal well, Well D, with an
effective lateral length of 2,400 ft, less than half mile to the north.
Due to lease constraints, only one well could be drilled from the Well
D pad.
Stimulating Wells A, B, and C involved both sequential and simultaneous
fracturing. Hydraulic fracturing of Well A was completed in five stages
during the first week, followed by simultaneous fracturing of Wells B
and C the following week.
Fig. 3 shows the production performance of the four wells over the
first 6 months of their production lives. The three simo- sequentially
fraced wells had IP rates of 3.3-3.5 MMscfd and the first month
averages ranged 2. 1-2.9 MMscfd.
The stand-alone Well D well to the north had significantly lower IF of
2.3 MMscfd and the first-month average production was lower, at 1.2
MMscfd.
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Montana BLM okays
Bowdoin gas field plan
Oil & Gas Journal / Dec. 15, 2008
A decision to drill new and replacement wells at a rate equal to the
retirement of no longer productive wells will keep the Bowdoin natural
gas field active for another 35-50 years, the US Bureau of Land
Management said on Dec. 5.
BLM officials in Montana announced a finding of no significant impact
as they approved a proposed alternative with additional mitigation for
the project by Fidelity Exploration & Production Co. and five other
producers who want to drill within one of Montana’s oldest gas fields.
They said that the field, which has been active from the 1 930s and has
about 1,450 wells, generally straddles the line between Phillips and
Valley counties south from the Canadian border to US Highway 2.
“Production from some wells that were drilled in the I 940s would be
restored by drilling new replacement wells from the original drilling
pads. In other instances, areas within the field that were previously
passed over would be tapped to increase productivity,” said Donato
Judice, supervisor in BLM’s Great Falls office.
Approved project components include up to 635 wells on individual
sites; construction of new access roads and associated facilities,
upgrading and use of existing roads; disposal of produced water with
evaporation ponds at each well site; use of solar, wind, and gas-fired
engines as external power sources, and installation of electric power
lines on a site-specific, case-by-case basis, and use of remote
electrical devices to measure temperature, pressure, and well flow at
each wellsite, the decision said.
Fidelity E&P is a division of MDU Resources Group Inc. of Bismarck,
ND, a holding company which also operates oil and gas pipelines and
electric and gas utilities from Minnesota to Oregon and Washington.
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Alabama Elusive shales need more work, Energen says.
OGJ.com Dec., 15 2008
Energen Corp., Birmingham, Ala., plans further exploratory tests in
2009 of Conasauga and Chattanooga gas shales in Alabama without partner
Chesapeake Energy Corp., Oklahoma City.
A three-well test program this year “generated neither positive nor
conclusive results,” said Energen (OGJ Online, Dec. 1, 2008). The 2009
tests may involve drilling more wells, testing alternative completion
techniques, and or completing other zones.
Energen doesn't believe the three wells have condemned the entire
acreage play, said John Richardson, president and chief operating
officer of Energen Resources Corp.
Chesapeake chose not to stay in due to financial considerations,
opportunities presented by other known shale plays, and the lack of
positive results, but Energen has the financial capacity to pursue the
plays on its own and will proceed in a low-risk manner, said James
McManus, president and chief executive officer of Energen Corp.
“In fact, all of our costs in this program to date, including
approximately $42 million in capitalized unproved leasehold, are less
than the $55 million pre-tax gain generated by the sale of one half of
our then-200,000-acre lease position to Chesapeake in October 2006,”
McManus said.
Energen, with a 330,000-acre net lease position in the acreage plays,
faces little lease expiration pressure in 2009. The two companies also
hold 14,000 acres outside the three areas.
The Energen-Chesapeake agreement permanently excludes Chesapeake from 9
surrounding sq miles if it elects not to participate in a well proposed
by Energen. Chesapeake could participate in other wells and could farm
out its 50% interest in the acreage to Energen or others, Richardson
noted.
Finding costs of less than $3/Mcf would be needed to make the shales
economic, he estimated.
Conasauga shale
The companies leased 351,000 acres south of the Appalachian thrust to
pursue gas in the Conasauga shale.
Energen and Chesapeake spud the Marchant well, in 22-22s-7w, Bibb
County, on Apr. 15, 2008, and drilled to TD 12,400 ft.
The well, which topped the Conasauga at 2,500 ft and topped a mushwad
zone at 4,000 ft, was drilled with little deviation or sticking,
problems that have plagued the wells at Big Canoe Creek field 75 miles
to the northeast in northern St. Clair County (OGJ, Feb. 19, 2007, p.
37).
Mushwad is an acronym for malleable unctuous shale, weak-layer
accretion in a ductile duplex. After the ductile Conasauga shale was
deposited in Cambrian time, Richardson explained, it “acted as a
lubricant that allowed the overlying strata to break and thrust upward
as they glide on top of the shale. The shale is piled up against
basement ramps and becomes thousands of feet thick.”
Energen acquired and reprocessed more than 1,000 miles of 2D seismic to
enhance the mushwad signature and gained enough comfort to drill some
distance from Big Canoe Creek field. Marchant 22-16 had eight
strong shows at 6,500-12,400 ft, and the companies attempted to
complete the deepest and most notable, at 11,525-730 ft.
The Conasauga is a carbonate-dominated sequence of interbedded shales
and carbonates alternating every few inches to every few feet,
Richardson said. “There is nothing like the Conasauga anywhere in the
country; it is a different kind of formation,” he said. A Sept. 15 frac
at 11,558-723 ft contained 165,000 gal of crosslinked gel and 220,000
lb of sand and resulted in a disappointing flow of less than 50 Mcfd
despite strong mud log shows.
This suggested that the completion technique didn't work but could be
the result of the geologic complexity of the mushwad, Richardson said.
“Our theory is that hydraulic fracturing may not be effective in
forming a conduit to enhance the production from a zone that is so
broken and deformed. If so, the question is, does this apply to all of
the mushwad or is it a localized occurrence? Our thought is to
hydraulically stimulate one or more of the additional zones of interest
in this well. If they do not yield satisfactory results, we may
consider lateral drillouts in order to contact more of the gas-bearing
rock,” Richardson said.
From 3,000 to 4,000 ft the same well encountered a zone “that was not
waded, had very low dip rates, and had slightly higher shale content
than the lower strata that was ultimately completed.
“This very thick zone at a shallow depth may offer some potential in
the future in a more traditional geologic setting,” Richardson said.
Chattanooga shale
The Chattanooga shale has long been of interest in Alabama because it
appeared rich in organics but was usually only 25-40 ft thick. Energen
and Chesapeake recognized the existence of a subbasin along the
Appalachian thrust with the potential for encountering intervals of the
Devonian age Chattanooga shale that were 100 ft thick or more,
Richardson said.
The Lamb 1-3H No.l, in 1-23n-3e, Greene County, was spud June 2 and
drilled with mud. It cut 93 gross and 91 net ft in Chattanooga at 9,150
ft. The 91 net ft refers to that portion of the gross interval that had
a gamma ray of 150 or more API units.
“We also encountered Floyd shale at 8,954 ft and several Pennsylvanian
aged sands from 6,000-8,000 ft,” he said.
Circulation was lost in several formations at 4,500-5,500 ft, making
detailed analysis of most of these zones difficult. “We were unable to
obtain a complete logging suite or a full core.” The incomplete core
implied encouraging values of porosity at less than 4% and permeability
a bit above 200 nanodarcies, Richardson said.
The companies gained enough encouragement to proceed with a horizontal
leg, but it encountered a fault. They kicked off at 9,150ft and drilled
a 2,035-ft lateral in the Chattanooga shale and ran a four-stage frac
totaling 2 million gal of slick water and 2 million lb of sand starting
Oct. 30.
After recovering 50% of the frac fluids, no significant gas flow was
recorded.
“We expected to see significant gas flows much earlier in the process.
That we did not calls into question the completion design or the
productivity of the shale itself,” Richardson said. “Our assessment at
this point is that we will likely drill and complete an additional well
in a different geographic setting. Hopefully this will encounter fewer
lost circulation problems and be in a better position to evaluate the
Chattanooga and Pennsylvanian sands potential.
“We also anticipate testing different completion and stimulation
designs. For example, after analyzing data gathered to date, we think
that using an energized fluid such as nitrogen in our stimulation may
be less reactive with the shale than slick water and could yield a
positive result.”
Chattanooga thrust/Floyd
The original concept with the Krout well was a mushwad-type formation
to the south and east of the main Conasauga play. The Krout 10-14 No.1,
in 10-22n-ge, Bibb County, was spud on Jan. 26.
“We found instead a thrust system that repeated the Chattanooga and
Floyd sections,” Richardson said. “This formation gave the appearance
of a mushwad on seismic due to the tectonic activity. It is very
structurally complex, overturned, and thrusted with highly dipping
formations.”
Mud logs from the Krout and Goodson wells 1 mile apart depict greatly
different geologic conditions. The Krout mud log shows five Chattanooga
sections and an abnormally thick Floyd section.
“It appears that the Floyd section has been overturned on itself and
has a gross thickness of more than 400 ft with a net thickness of 158
ft as measured by gamma ray of more than 150 API units.”
The companies attempted completion in the Lower Chattanooga at 8,210-50
ft and 8,300-90 ft. This zone had 130 ft of net Chattanooga shale. A
hydraulic frac on Oct. 8 with 200,000 gal of cross-linked gel and slick
water and 150,000 lb of sand yielded a disappointing flow of less than
50 Mcfd.
“Therefore,” Richardson said, “we have no plans for future Chattanooga
shale completions in this play, but we do plan to evaluate the
abnormally thick Floyd that we encountered.”
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Italian pipeline
developers undeterred by credit crunch
Uchenna Izundu International Editor OGJ Dec 15
The Galsi and Interconnector Greece-Italy (IGI) pipeline partners do
not expect the credit crisis to negatively impact their plans, as they
have very strong balance sheets, according to a senior company
official.
However Elio Ruggeri, project leader at the department of hydrocarbons
at Edison SPA, told OGJ at the European Autumn Gas Conference (EAGC) at
Lake Como, Italy, that securing gas supplies from Shah Deniz for the
IGI line was difficult due to limited available volumes and intense
competition from different markets. “Russia and Turkey will also have a
share of this gas,” he said. No contracts have been signed to fill the
IGI pipeline.
Enhancing security
Edison is a partner in both projects, which are expected to enhance
Italy's gas supply security. Gas demand in Italy should grow to 96-104
billion cu m/ year in 2015 from 85 billion cu m/ year in 2007,
according to Ruggeri. Gas imports are expected to increase to 26
billion cu m/ year by 2015, up from 18, and the incremental need for
import capacity is expected to rise to 41 billion cu m/year by 2015, up
from 32.
Currently, the Italian gas market is tight. But demand destruction in
natural gas has already begun, warned Davide Cornaggia, supply and
sales director at mid-size operator Gas Plus Italiana SPA. “Customers
are consuming less, and gas use for power generation has decreased in
the last 2 months by a substantial amount. I understand that this has
also happened elsewhere.” The nation faces a dilemma where there is a
risk of a gas bubble in the summer of 2009, Cornaggia added. With these
projects, along with Italian LNG import terminals, there could be an
oversupply of gas in the medium term.
Ruggeri said Italy could become a gas transit country for France and
Germany provided the pipeline system becomes integrated in Europe.
The Galsi partners, including Sonatrach, Enel SPA, Sfirs (Sardinia
Reg), and Hera SPA, plan to make a final investment decision next year.
The front-end engineering design (FEED) work is to be finished by
yearend 2008. Tenders for the engineering, procurement, and
construction contract are being prepared along with the financial
structure for the project.
Sonatrach leading way
Sonatrach is leading the proposed 840-km Galsi pipeline, which will
have a capacity of 8 billion cu m/year and in 2,800 m of water will be
one of the world's deepest offshore pipeline ever laid. It will deliver
Algerian gas via Sardinia into Italy starting in 2012. The definition
of the transportation contracts between Galsi and its shippers are
being drawn up. This pipeline would connect Sardinia for the first time
to Italy's national grid and improve its environmental footprint.
According to a memorandum of understanding signed in September by Galsi
and Snam Rete Gas (SRG) , Galsi will be responsible for the FEED and
securing permits with SRG's help during the development phase. Galsi
will build, own, and operate the international section while SRG will
concentrate on the national section.
The IGI line is an 800-km pipeline that would deliver 9 billion cu
m/year of gas from the Caspian to Italy and Western Europe via Turkey
and Greece in 2012. However, to meet this deadline, gas supply
agreements and gas transit agreements must be finalized within the next
year to make the final investment decisions in 2009.
Edison will take 6.4 billion cu m/ year, and its Greek partner Depa
will have 1.6 billion cu m of capacity in IGI, which has been exempted
from third party access under European Union rules. Ruggeri said 1
billion cu m/ year of gas has been set aside for third parties and
there has been 17 non-binding expressions of interest (EO I) from
Italian and other companies under the open season held in June.
“We don't know how much capacity had been applied for as we didn't ask
for this figure under the EOI,” Ruggeri said. “There were two lots of
100 million cu m each that were offered, and I suspect that people
would have bid for the entire capacity.”
During the next phase, the IGI consortium will ask interested shippers
to submit binding offers to reserve transportation capacity, which will
be followed by an allocation stage.
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Haynesville gas flows
as high as 28 MMcfd
OGJ.com 12/27/08
Three operators reported new horizontal completions in Jurassic
Haynesville shale at rates as high as 28 2 MMcfd of gas.
The three companies, Petrohawk Energy Corp. of Houston and Comstock
Resources Inc. and EXCO Resources Inc. of the Dallas area, plan much
more activity in the Haynesville in East Texas and Northwest Louisiana.
Petrohawk reported the 28.2 MMcfd rate at its Sample 9- 1 in 9-14n-l
1w, Red River Parish, La., about 12 miles south of Elm Grove gas field.
The rate came on a 30/64-in, choke with 7,100 psi flowing casing
pressure.
Petrohawk’s Brown 17-4 in 17-1 6n- 11w, Bossier Parish, gauged 23.4
MMcfd on a 26/64-in, choke with 7,700 psi FCP And its Goodwin 9-5 in
9-16n-llw Bossier Parish, made 21.1 MMcfd on a 26/64-in, choke with
6,750 psi FCP The company plans to complete five more Haynesville shale
wells by yearend 2009.
Initial flow rate is 9 MMcfd at Comstock’s BSMC LA 7-1 H well in Toledo
Bend North field, De Soto Parish. The flow came from a 4,300-ft lateral
at 11,750 ft true vertical depth after a 10-stage frac.
Comstock is running another 10-stage frac at its Collins LA 15-IH well
in Logansport field, also in De Soto. It has a 4,200-ft leg at 11,350
ft. The company has a 22% interest in the Gamble 24-1 H well at
Logansport, drilled to 11,800 ft TVD with a 3,950-ft lateral.
Comstock has drilled the vertical portion of two other Haynesville
wells. Bogue A-6H in Waskom field in Harrison County is to get a
4,000-ft lateral, and Green 1 3H in Blocker field in Harrison County is
to get a 3,700-ft lateral. Comstock is drilling vertically at Headrick
1 H and Hart I H in Logansport and Moneyham 7H in Longwood field. Each
is due a 4,000-ft leg.
EXCO said its first Haynesville horizontal well, Oden 3 0H6 in De Soto
Parish, averaged 22.5 MMcfd on a 26/64-in, choke with 7,800 psi FCP It
has a 4,481-ft lateral at 12,304 ft TVD.
EXCO has two operated horizontal wells, one vertical well, and two
outside-operated horizontal wells in the play and plans to drill 25 or
more horizontal Haynesville wells in 2009.
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Marcellus - Cabot to hike Pennsylvania program
OGJ.com 12/27/08
Cabot Oil & Gas Corp., Houston, plans to boost production from
Devonian Marcellus shale in northeastern Pennsylvania in the next few
weeks from the current 1 3 MMcfd as it hooks up six vertical and three
horizontal wells.
Meanwhile, the company expects to expand to eight rigs in 2009 from the
five currently working.
Cabot’s first horizontal Marcellus well came on line at 6.4 MMcfd after
a six-stage frac in its 2,000-ft lateral. Measured total depth is 8,925
ft.
Marcellus drilling totals 18 wells, 4 of them horizontal. The 2009
program calls for 16 vertical and 7 horizontal wells. Four vertical and
3 horizontal wells remain to be drilled in 2008.
Typical costs are $1.3 -1.5 million for a vertical well and $2.6-2.9
million for a horizontal well. Average footage is 7,200 vertically and
2,200 ft laterally.
The company laid 10 miles of pipeline, started up one compressor with a
second unit standing by as produced volumes warrant.
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