What constitutes a Deemed Liability?
This is the final in the series on Liability
QUESTION: How does the Alberta Energy Regulator (along
with most regulators in North America) define licensing risk?
What is not included in the deemed liabilitycost used in
the LLR program?
• Suspension
• Abandonment
• Remediation
• Reclamation
ANSWER: LLR Risk Ratio threshold is 1.0
If LLR ≥ 1.0 » NO security required
If LLR < 1.0 » security required
The KEY here is the number 1. Operating ratios expected in
this rating process are:
1 well that is NOT a liability – not making money
Must be off-set by
1 well that IS an asset - making money
How does this effect a license transfer?
• Applications are submitted through the Digital Data
Submission (DDS) system
• Both Transferor and Transferee must declare all transfer information is accurate and approve the transfer
• A single application can include wells, facilities and
• Have 30 days to satisfy deficiencies; transfers closed
at 90 days
When that ratio slides to the “more wells not making money”
a security deposit is required.
Our regulatory review section provided a risk matrix associated to particular types and ages of wells, this provides a bit
of guidance on higher risk wells and the requirements necessary for the implementation of a management plan to address
A purchase and sales agreement means you sold the assets,
You are still the responsible licensee UNTIL AER transfers
the licenses. Licences with the following status’ cannot be
transferred: RecCertified, RecExempt, Cancelled, ReEntered.
Liability Summary
• Licensee’s are responsible for end of life costs, suspension, abandonment, remediation and reclamation
• Perpetual abandonment responsibility
• Contamination – joint and several liability
• Reclamation – 25 years
What constitutes a Deemed Asset?
LLR program – compare assets to liabilities,
less than one, then pay security.
License transfer – liability termination after
AER approves.
Next Issue - Dealing with the LLR and Liability Management
proven leader in oil sands recovery, and hopes to collaborate
and share knowledge.
The AER has established a panel of hearing commissioners
to conduct a proceeding into odours and emissions associated with heavy oil operations in the Peace River area. The
purpose of the proceeding is to examine the issues and
concerns of Peace River area residents related to odours and
emissions associated with heavy oil operations in the Peace
River area. The proceeding will also provide a public process
by which concerned stakeholders will be afforded a formal
opportunity to have their views, concerns and advice considered by the Panel in completing its mandate. The proceeding will be conducted in accordance with the principles of
fairness, transparency, thoroughness, and inclusivity. - See
more at: http://www.aer.ca/applications-and-notices/hearings/proceeding-1769924#sthash.CKyojX4l.dpuf
Mississippi and Alabama are taking a leaf out of the Canadian
playbook by exploring the potential of oil sands reserves in
their states.
The two southern U.S. states signed a memorandum of understanding (MOU), to explore the potential of oil sands
resources in The Hartselle Sandstone play that stretches from
north-central Alabama to northeastern Mississippi. The development is estimated to contain 7.5 billion barrels of oil
sands, with 350 million barrels located within 50 feet of the
surface, according to the MOU, citing evaluations done in the
1980s. The assessment will include analysing the infrastructure,
legal framework along with a more updated estimate of the
reserves. The two states are situated close to the Gulf Coast
refineries that consume heavy oil from Canada. “The Governors
recognize the need for a comprehensive geologic and engineering assessment of the States oil sands resources and an
analysis of the legal and regulatory frameworks applicable
to resource development,” the two governors stated in the
MOU. Mississippi Governor Phil Bryant said the states will be
seeking help from the Government of Alberta, Canadian
universities and the Canadian Consulate General in Atlanta,
to help assess the reserves. Last year, the Canadian Consulate
General in Atlanta, and the Alberta government hosted
Southern States Energy Board members and geologists from
Alabama and Mississippi for a series of meetings and tours
highlighting the oil sands operations in the province.
Abandonment and Reclamation Oil and gas companies operating in Alberta must abandon all dry holes or wells that
are no longer producing, typically by pouring cement down
the wellbore and removing all wellhead equipment. Once a
well has been abandoned, the company must return the land
to its original state. This process, known as reclamation, must
be completed before the company will be allowed to leave
the well site. - See more at: http://www.aer.ca/rules-andregulations/by-topic/abandonment-and-reclamation#sthash.
October 2013 abandonment order listing has 17 full pages of
companies the regulator is requesting abandonment on wells/
facilities. The cumulative abandonment order listing has 61
full pages. That adds up to a great deal of wells to be abandoned. This process must now also take D79 Surface
Development in Proximity to Abandoned Wells into
consideration when planning the abandonment and monitoring process.
THAI (toe-to-heel air injection) technology recovery methods,
is a evolutionary new combustion process, that combines a
vertical air injection well with a horizontal production well.
This new method of extracting oil from heavy oil deposits
which may have significant advantages over existing methods
was developed by Malcolm Greaves of the University of Bath
and has been patented by Petrobank. During the process a
combustion front is created where part of the oil in the reservoir is burned, generating heat which reduces the viscosity
of the oil allowing it to flow by gravity to the horizontal
production well. The combustion front sweeps the oil from
the toe to the heel of the horizontal producing well recovering an estimated 80 percent of the original oil-in-place while
partially upgrading the crude oil in-situ.
Two U.S. states are asking Alberta for help on the idea of their
own oil sands industry.
In-situ recovery of bitumen resources in Northwestern Canada
occurs in the near surface (deeper than 75m and typically
less than 600m). The recovery method patented and used
by Petrobank is known as Toe-to-Heel-Air-Injection (THAI®),
which is an in-situ combustion process that is used for the
recovery of bitumen and heavy oil. It combines a horizontal
production well with a vertical air injection well placed at the
toe. This is an in-situ combustion process which burns the
heavy end asphaltenes of the bitumen to mobilize and
upgrade oil in-situ, while recovering up to 65% of the bitumen.
Mississippi and Alabama are exploring bitumen reserves in
their states, and say they’ve signed a memorandum of understanding to explore a reserve that stretches across
both states.
Mississippi governor Phil Bryant says they’ll look for help from
the provincial government, Canadian universities, and the
Canadian consulate in Atlanta. He says he sees Canada as a
single operation, yielding improved well economics. The MZST
process was developed by ExxonMobil Upstream Research
Company in Houston, Texas and was recognized with Platts
Global Energy Award for Most Innovative Commercial
Technology in 2005.
Because of the shallow depth of operation in combination
with the properties of bitumen, where the oil is part of the
formations matrix, this process produces large changes in
the reservoir and also in how the formation carries and distributes a load (Wikel, 2012). Therefore, this affects how the
reservoir and overburden distribute regional and local stresses.
This requires monitoring of the reservoir during combustion
and for stress changes in the formation of interest. In addition
to this, the overburden must be monitored and studied to
ensure cap rock integrity through time. This will help us avoid
well damage or surface venting of pressure. Time lapse multicomponent studies are well suited for this purpose.
The MZST process can be particularly beneficial for fracturing
operations in tight gas, shale gas and coal bed methane wells
that target multiple reservoir zones, thick reservoir sections,
or long reservoir intervals where multiple stimulation treatments are required. The MZST process will enable Canyon
Technical Services to optimize its stimulation operations by
combining the deployment of perforating and fracturing
equipment simultaneously in the wellbore to enable singletrip, multi-zone stimulations. This proprietary technology
dramatically increases the number of zones that can be
fractured per day compared to conventional fracturing and
stimulation operations. Canyon Technical Services provides
leading edge well stimulation and cementing technology to
customers in Canada.
Momentive Specialty Chemicals’ Oilfield Technology Group
(OTG) has released a new resin-coated proppant technology
for fracturing service companies and operators in the Canadian
oil and gas industry. Momentive’s Yukon Black proppants are
a next-generation resin-coated sand that bonds at low temperatures. These proppants are ideal for fracture treatments
in the low-temperature reservoirs in Canada, where flowback
control is necessary. Low-temperature bonding, down to
70°F bottom-hole static temperature, is achieved without the
use of a consolidation aid.
Oil Lift Technology announced that it has opened a new
manufacturing plant in Calgary, a 50,000-square-foot facility
that will now allow the company to produce the entirety of
its progressing cavity (PC) pump systems in-house, providing
complete control over the fit, quality and durability of its
products. The new facility, along with its expanded production capabilities, will enable the company to continue to
enhance its commitment to industry manufacturing precision.
The company designs and manufactures rotors and stators,
develops specialty elastomers, and produces other critical
pump components based on the exact needs of its customers’ well conditions. The company has field service facilities
in Canada, the United States, Australia, Colombia and Oman,
and has manufacturing facilities in Calgary as well as Brisbane,
Australia. The new 4,645 sq m (50,000 sq ft) facility will allow
the company to produce the entirety of its PC Pump systems
they can offer its customers. The company, which also was
recently acquired by the Dover Corp., designs and manufactures rotors and stators, develops specialty elastomers, and
produces other critical pump components based on the exact
needs of its customers’ well conditions.
Along with these features, the Yukon Black proppant Stress
Bond technology delivers all the typical advantages of a
curable resin-coated proppant. This includes proppant flowback control, proppant embedment minimization and proppant fines reduction, which all lead to enhanced well production. These advanced new proppants are being manufactured
in Momentive’s proppant production plant in Sturgeon County,
near Fort Saskatchewan, Alberta.
Resin-coated proppants are used in the hydraulic fracturing
process to help optimize production from oil and gas wells
by maximizing fracture flow capacity, from the reservoir to
the wellbore. Technological innovations and the company’s
introduction of enhanced materials have expanded the use
of resin-coated proppants into unconventional reservoirs that
feature complex and challenging geological formations.
Rotary Steerable Systems (RSS) technologies shall be providing case studies of the Canadian foothills. These operations
are situated in a challenging drilling environment with deep
wells in hard, abrasive formations that lead to extended drilling time. Casing wear can occur in the upper sections, and
special care must be taken to ensure casing integrity throughout the life of the well. Studies have shown that even slight
doglegs in this vertical section lead to localized “hot spots,”
where erosion of the casing is focused. Keeping the well
straight in this highly dipping formation has been a priority
for drilling companies and operators. Rotary Steerable
Exxon Mobil Corporation announced the licensing of its
award-winning Multi-Zone Stimulation Technology (MZST)
well treatment process to Canyon Technical Services Ltd. of
Calgary, Alberta, Canada. The MZST process can be used to
rapidly and reliably stimulate multiple reservoir zones in a
is the Keystone XL project, seen as a major conduit for connecting Alberta’s oilsands in the north to Texas refineries in
the south. However, the Upton-Green bill would need to
navigate many obstacles before it could become law. Under
the U.S. congressional system, both the Senate and House
of Representatives must pass identical bills before the proposal goes to the president, who has veto power.
Systems (RSS) have assisted in drilling wells in the Canadian
Foothills. Using a “closed loop” feature, which automatically
seeks a vertical profile in an openhole sidetrack with a carefully controlled dogleg severity (DLS), the rotary steerable
tool is proving useful in drilling wells and reducing risks.
U.S. National Research Council published a study showing
that diluted bitumen contains no attributes that make pipelines more vulnerable to erosion, external corrosion or cracking
than other types of oil.
B.C.’s liquefied natural gas sector received a provincial government push Monday with the approval of $116 million in
tax breaks to support continued drilling in the province’s
northeast, along with an environmental pull from an environmental group looking to pin government down on a definition
of “clean” LNG. The tax breaks are royalty credits to companies
proposing to build 12 road and pipeline projects which are
designed to interconnect wells with the province’s collection
and distribution system. The province has explained the
credits as a way to encourage companies to spend on infrastructure that jumpstarts drilling activity that wouldn’t have
had happened otherwise. Minister of Natural Gas Development
Rich Coleman said the government brings in less money
because of these credits, but it is the industry that builds
roads and bridges within production regions. “What it has
done for us is it’s built the infrastructure we’ve needed to
have for movement of goods and services into well sites,”
Coleman said. Coleman said the construction projects will
inject $320 million into the region to build the
dozen projects.
That being said, companies have spent years researching and
developing pipeline products for the oil sands that better
withstand corrosion and the elements. Enter Sherwood Park’s
ClearStream Wear Technologies facility (pictured at right),
whose chromium carbide overlay systems can extend the
life of a carbon pipe by up to 10 times, equating to less down
time and increased productivity for users, according to VicePresident of Wear Technologies for ClearStream, Chris Cloutier.
Wear Technologies is now the largest manufacturer of chromium carbide overlay pipe and fittings in the world. The
overlay is applied to carbon steel pipe in various diameters
up to 60 inches, and lengths up to 40 feet, after the pipes
are sandblasted in a process involving an average of 14 automated machines. The prime component in the pipe overlay
system is the chromium carbide wire, which the company
manufactures in-house. In any given month, the company
will go through 60,000 pounds of the wire to fabricate
its pipes.
While low gas prices have driven down royalty payments - to
just under $200 million last year compared with $2 billion at
their peak, Coleman said the credits still expand activity and
“the back-end (of production) is higher than it would be today.”
The province estimated that it will see $445 million in royalties over the next 25 to 30 years through increased drilling.
Tides Canada released a report chiding the government for
its use of the term “clean LNG.” Merran Smith, director of
Tides’ Clean Energy Canada Program, said the report was
sparked by the province vows to produce “the cleanest LNG
in the world,” without defining what that means. “When we
did a scan from the carbon perspective, we’re on track to
producing LNG that’s going to be three-times dirtier than
the ‘cleanest LNG’ in the world,” Smith said. Tides takes its
clean standards from two plants, a Statoil LNG facility in
Norway and the Gorgon facility in Australia, both of which
employ carbon-capture and storage of excess C02 from gas
wells at the drill head, and electric-drive equipment in gas
processing and at the liquefaction plants rather than directdrive systems that burn natural gas to operate equipment.
“Frankly, I think we cannot afford not to make this investment,
if we want to be world class and cleanest,” Smith said, but
will require strong policy decisions by government.
This divison of ClearStream Energy Services produces between
2,000 and 2,500 overlaid pipes on a yearly basis, good
enough for $50 million a year in revenues and busy
enough to keep 265 workers employed at the 24-hour-a-day,
six-day-a-week operation.
The U.S. House of Representatives have proposed a bill which
would overhaul how cross-border energy projects such as
the Keystone XL oil pipeline are reviewed, limiting the process
to months and taking the decision out of the State
Department’s hands. Under the North American Energy
Infrastructure Act, co-sponsored by Michigan Republican
Fred Upton and Texas Democrat Gene Green, such a project
would have to be approved within 120 days, unless it’s found
be against the national security interest of the United States.
Such decisions on oil pipelines would be made by the secretary of commerce, rather than the secretary of state and
president, as is currently the case under the Presidential
Permit process. One of the casualties of the current system
Canadian energy giant Cenovus will soon make military veterans a priority when hiring new employees. Federal Veterans
facility would use
Canadian Pacific’s
North Main Line for
transporting crude
by rail to markets
a c ro s s
America. A unit
train is a series of
Affairs Minister Julian Fantino took part in an announcement
Wednesday that Cenovus Energy Inc. has joined a program
which was announced last fall as part of a government veterans transition plan. “Cenovus Energy is giving veterans new
and interesting opportunities to make a successful transition
from military to civilian life,” said Fantino. “The type of training that veterans receive, it’s regimented, it’s geared in many
different areas ... and things are very well structured,” he said.
“Very often transitioning into a different kind of environment
in civilian life can be challenging.”
Gibsons rail tanker
rail cars designed for one specific purpose, such as transporting crude oil, that is not split up or stored en route to its
destination. Unit trains save time, money and inconvenience
for customers. A unit train of 100 cars could transport about
60,000 barrels of oil sands crude, or about 12 per cent of the
daily capacity of the proposed expansion of the Trans
Mountain pipeline, which runs from Edmonton, Alta. to
Burnaby, BC.
Jim Grecco spent 27 years in the Canadian Air Force before
retiring in 2000. He’s now the military liaison manager with
Cenovus. “When you get outside the military and you come
into industry, you find that there are a lot of things that the
military has taught you: communications, problem-solving,
leadership,” Grecco said. “Those things are applicable anywhere in this country (whether in uniform or out of uniform)
and a lot of military people don’t recognize that.” Cenovus
plans to inform veteran affairs groups of job opportunities,
so those looking for work are aware of openings. “If we have
equally qualified candidates for the same role, we will offer
the role to the veteran,” said Jacqui McGillivray, Senior VicePresident at Cenovus. “We’ve been actively working with the
Canadian military... on opportunities to hire because the
quality of individuals from the Canadian Armed Forces is
exceptional – the leadership, technical expertise, the experience. They bring great skills into an organization.”
The multibillion-barrel trove of energy that lies trapped in
tombstone-dense rock across a vast tract of west-central
Alberta is not all in the hands of the oil majors, says Brian
McLachlan, Chief Executive Officer of Yoho Resources Inc.
He has quietly amassed 21 net sections in the Duvernay, in a
window he believes is ideal for tapping a rich vein of rock
soaked in petroleum liquids like propane and ethane.
Other producers, including Encana Corp., Talisman Energy
Inc., Shell Canada Ltd. and Chevron Corp., have followed suit,
spending more than $3 billion since 2009 snapping up land
in the sprawling formation, which could hold 11.3 billion barrels
of natural gas liquids, plus 440 trillion cubic feet of natural
gas and 61 billion barrels of crude oil, if appraisals by Alberta’s
Energy Regulator (AER) prove correct. By all appearances,
McLachlan has positioned Yoho at ground zero of Alberta’s
next petroleum bonanza. “So far we’ve had pretty good luck,”
he says, noting that individual sections his company bought
for $20,000 would now fetch $3 million. “Getting in early
does help,” he adds, “especially when it starts working.”
Cenovus is a leading Canadian oil company which employs
about 5,000 people. Its operations include oilsands projects
in northern Alberta and natural gas and oil production in
Alberta and Saskatchewan. It’s the first energy and utility
company to participate in the job creation initiative. Toronto’s
Hospital for Sick Children was the last organization to sign
onto the program a few months ago. Fantino said support
for the program is growing. “Certainly the private sector
recognizes more and more the value, the skill sets, the discipline ... and the kind of opportunities that are inherent to
the training and experience the veterans have had,”
Fantino said.
Alberta Crown sales have dropped dramatically since the
buying frenzy of 2009. Sales of drilling rights totaled $579
million in the first six months of fiscal 2012, the province said
in a second-quarter update. A recent land sale netted just
$13 million, or $2 million shy of what Encana says it will cost
to drill a single well on its Duvernay acreage. The slowdown
underlines the shift away from resource appraisal, the slow
work of peering under rocks and gathering data in a shale
play said to rival the Eagle Ford in Texas in size and potential
production. “Everyone’s at varying stages of development
depending on when they got in,” says McLachlan, whose
outfit pumped an average of 2,200 barrels of oil equivalent
in the year ended September 30, 2012. “But if you look at,
Gibson Energy has signed a letter of intent to explore the
construction of unit trains to ship oil sands crude and conventional oil. While debate heats up over pipeline construction
in BC and the United States, a Calgary-based transportation
company is gearing up to ship oil sands crude by rail. Gibson
Energy Inc. announced announced that it has signed a letter
of intent with a major unit train developer to explore unit
train shipments from the Hardisty, Alta. area. The proposed
some of the Encana leases that they’ve licensed wells off of,
the actual survey shows an eight-well pad. Shell’s drilling two
wells off a pad already, so they’re actually ahead of us.”
Hydraulic fracturing crews and completions outfits are among
those mobilizing in response to the activity. Trican Well Service
Ltd., to take one example, recently moved into a renovated
lumber mill on a 25-acre lot in Hinton to capitalize on new
business in the region. It also owns operation bases in nearby
Grande Prairie and Whitecourt. Like others, Trican has been
experiencing tumbling natural gas prices and the resulting
slowdown in field activity. Third-quarter revenues fell 13 per
cent last year, to $322 million, as the number of active drilling
rigs in Western Canada fell by 28 per cent and completions
declined 31 per cent compared to a year earlier. Canadian
pricing declined six per cent over the same period, the
company said. A shift away from exploratory drilling toward
“pad” production in the Duvernay might help reverse that
trend, suggests Rob Cox, Vice-President of Trican’s Canadian
geographic unit. He says a “major” client is planning a fourwell pad in the play, although he won’t say whom. “That tells
us you’re getting past the exploratory phase and closer to
the development phase,” he says in an interview.
real key,” says Andrew Beaton, Manager of the AER’s resource
appraisal group, “is finding that right match where you have
the right rock characteristics where you can actually get
those liquids out.”
Producers that perfect the combination stand to make a lot
of money. Energy consultancy Wood Mackenzie projects the
Duvernay is so soaked in condensate that individual wells
could generate revenue of between $4.6 million and $5.6
million each on a net present value basis.
Such windfalls only partially offset the capital required to
commercially develop modern resource plays, however.
McLachlan, who served as a director at Progress Energy
Resources Corp., is not oblivious to the challenges faced by
small companies with large holdings in promising resource
plays. Yoho recorded an $8.8 million loss on falling gas prices
in its last fiscal year. The company is carrying $18.5 million in
debt and plans to spend between $35 million and $38 million
this year, most of it in the Duvernay.
It takes a “small town” of equipment to bring a shale gas or
oil well on stream, McLachlan says, turning philosophical.
“Maybe the small company’s role has changed,” he muses,
comparing Yoho to a junior mining outfit. “I don’t think this
is a heck of a lot different,” he says. “We’re delineating the
mine, and maybe we cut a deal with the BHP [Billiton]s of
the world to spend the big money.”
The Duvernay is particularly attractive to pressure pumpers;
it takes more energy to blast fissures in the formation that
let trapped gas and oil flow. Horsepower requirements in the
Duvernay, on wells with up to 15 stages per bore, are “on the
high side, for sure,” Cox says, ranging from 17,000 to 30,000
hydraulic horsepower. “So you’re talking about needing anywhere from 15 to 20 or more horsepower pumpers just to do
a frack.” Along a two-lane rural highway northwest of
Edmonton during a late-November storm, convoys of halftonne pickups, pressure pumpers and mobile rigs kick up
their own weather systems of blowing snow and howling
wind. The trucks hauling gear into and out of hidden well
sites belong to oilfield service giants Schlumberger, Halliburton
and Baker Hughes, who have followed the explorers into the
heart of the Duvernay. In the service hub of Whitecourt, Mayor
Trevor Thain reports the telltale signs of an oncoming boom.
For drillers, the Absence of Amenities located in close
proximity to the most promising acreage only serves to increase exploration costs. Last year, for instance, Yoho pumped
$13.5 million into just one well – about 70 per cent more than
what the company raised in a private placement of securities
last fall. “But you’ve got to remember, this is one well,”
McLachlan says. “You’ve got to move in all that water, all that
equipment, for one well.” He says costs will fall when multiple
wells are drilled from a single pad. “You can imagine how
much more efficient that is,” he says. Convoys of half-tonne
pickups, pressure pumpers and mobile rigs kick up their own
weather systems of blowing snow and howling wind.
A $2.2 billion deal between PetroChina and Encana Corp. will
fast track development on more than 400,000 acres in
Alberta’s Duvernay shale, the Calgary-based natural gas
company said in a statement today. Encana, Canada’s largest
natural gas producer, agreed to sell a non-controlling 49.9
per cent interest in roughly 445,000 acres in the Duvernay
shale to Phoenix Duvernay Gas, a wholly owned subsidiary
of PetroChina, for a total consideration of $2.18 billion. The
deal came after Ottawa introduced new investment rules for
foreign state-owned enterprises in the oil patch. Those rules
barred so-called SOEs from taking majority positions in oil
sands companies but left the door wide open for natural gas
assets. Encana said $1.18 billion will be paid on closing, with
$1 billion payable over the next four years in the form of carrying half of Encana’s development costs. The two companies
plan to invest a total of $4 billion in new drilling, completion
and processing facilities in the sprawling play, according to
the statement. Encana estimates its holdings contain roughly
9 billion barrels of oil equivalent in place. The arrangement
will help Encana more than double its planned pace of development in the Duvernay, according to the statement.
Another reason for optimism: monster yields of condensate
and a ready-made market located next door in the oil sands.
The ultra-light oil, typically fetches a premium to the North
American benchmark, West Texas Intermediate, is used by
oil sands producers to make bitumen flow in pipelines. “The
There was also a $5.4 billion partnership agreement between
the two companies to develop shale gas properties in British
Columbia that collapsed in 2011, hastening asset sales at
Encana amid tumbling natural gas prices. Encana will retain
the operator title in its new arrangement with PetroChina.
The company said it expects to end 2012 with cash balances
in excess of US$3 billion, ahead of an earlier divestiture target
of $2.5 billion. The Calgary gas producer also says it has
increased its hedge position for the year ahead to roughly
1.5 billion cubic feet per day at an average price of $4.39 per
1,000 cubic feet.
collecting field data and engaging with aboriginal and stakeholder groups on the project.
Red Flame Industries Inc. (RFI) has joined forces with
Pittsburgh-based Bolttech Mannings Inc. (BMI) in a strategic
move that will create business synergy as it expands; bringing
more jobs to Alberta. The two companies officially announced
BMI’s acquisition of RFI in mid-May. This important step was
taken after lengthy negotiations. The fit between Red Flame
and Bolttech Mannings seems to be a natural one with the
two companies offering complementary services within the
same industries. BMI brings 35 years of corporate history and
a broad portfolio to the table, with services that include industrial bolting, induction services and on-site machining for
the oil, gas, petrochemical, steel, power generation and offshore industries. Red Flame Industries, as full-service plant
and pipeline specialists with a 16-year history, offers inspection,
repairs and certification of lifting and pressure equipment
along with a complete hot tap solution. Red Flame’s industry
focus includes the oil, gas, petrochemical and renewable
resource industries. The two companies share the same core
values: focusing on customer needs, worker safety, the provision of quality work and an emphasis on continuous improvement and innovation. Through its strategic alliance with
Bolttech Mannings, Red Flame Industries is looking to take
full advantage of the tremendous growth opportunities in
Alberta. BMI’s strengths lie in power generation; as this industry
expands in Alberta, Red Flame is now positioned to branch
out from oil and gas into this expanding service market. Red
Flame will benefit from its new presence in BMI’s 20+ US field
offices, and an expansion of its services that will now include
bolting, torqueing, tensioning, heat treatment and field machining. With additional services and product lines resulting
from the acquisition, Red Flame also expects to increase its
workforce of qualified technicians and to provide valuable
opportunities for current staff to learn additional skill sets.
Jared Sayers, Founder and CEO/President of Red Flame, will
continue to lead the company from Red Deer, Alberta.
Canada’s largest pipeline operator TransCanada Corp will
proceed with the construction of its $12-billion crude oil
pipeline project from Western Canada to refineries and export
terminals in the east. The proposed 4,400-km Energy East
pipeline will have the capacity to carry 1.1 million barrels of
crude oil per day (b/d) from oil-rich provinces of Alberta and
Saskatchewan to refineries in Quebec and New Brunswick
and to marine facilities for export to energy-hungry Asian
markets. The decision was based on binding, long-term
contracts received from producers and refineries for approximately 900,000 b/d of oil, TransCanada said in a press
release. TransCanada’s President and Chief Executive Officer
Russ Girling said, ‘’We are very pleased with the outcome of
the open season for the Energy East pipeline held earlier this
year and are excited to move forward with a major project
that will bring many benefits across Canada.’’ ‘’This is a historic
opportunity to connect the oil resources of western Canada
to the consumers of eastern Canada, creating jobs, tax revenue
and energy security for all Canadians for decades to come.’’
Girling further stated. The proposed pipeline is expected to
provide a stable and reliable alternative to refineries in the
east by securing access to cheaper Western Canadian crude
oil compared to more expensive imported oil. Eastern Canada
currently imports around 700,000 b/d of crude.
The mammoth project involves conversion of an existing
3,000-km natural gas pipeline to an oil pipeline as well as
construction of 1,400 km of new pipelines in Alberta,
Saskatchewan, Manitoba, Eastern Ontario, Quebec and New
Brunswick to link up with the converted pipeline. It will commence from a new tank terminal in Hardisty, Alberta with
three more terminals along its route: one in Saskatchewan,
one in Quebec City and another in Saint John, New Brunswick.
The pipeline will terminate at Canaport in Saint John where
TransCanada and energy producer Irving Oil have formed a
joint venture to build, own and operate a new deep water
marine terminal. The ice-fee port can handle the world’s
largest oil tankers, which substantially reduces shipping costs
on long-haul routes to Asia. The new pipeline is expected to
become operational by 2018. Calgary-based TransCanada is
a major North American energy company operating oil and
gas pipelines, power plants and other related facilities.
Prior to TransCanada Corp. securing a favorable environmental
review from the U.S. State Department this summer for its hotly
contested Keystone pipeline expansion, industry participants
were assuming the project would be built. “That would be the
producers’ assumption today,” Ian Anderson, President and
Chief Executive of transportation rival Kinder Morgan Canada,
told Alberta Oil during a lengthy interview last summer. “If that
somehow changed, and either it didn’t occur or it occurredmuch
later than planned, I think that will do nothing but increase
pressure to add more pipeline capacity sooner to the West Coast.”
The company’s assets include a gas pipeline network extending more than 68,500 km, 400 billion cubic feet gas storage
facilities and interests in over 11,800 megawatts of power
generation in Canada and the US. TransCanada said that it
will proceed with the necessary regulatory applications in
early 2014. The company said that it has already commenced
That pressure was already building as officials with the State
Department issued their third environmental assessment of
the $7-billion Keystone application last summer. As officials
at the State Department weigh final approval of the Gulf
Coast delivery system, a suite of West Coast expansion plans
are quietly gathering momentum. Enbridge Inc. says its
multibillion-dollar Northern Gateway project is now supported
by so-called precedent agreements with prospective shippers.
And a group of oil sands producers including Cenovus Energy
Inc. and Nexen Inc. has told the National Energy Board (NEB)
that an application for firm service on Kinder Morgan’s Trans
Mountain pipeline (TMPL) to Burnaby, British Columbia,
amounts to a “first step” in opening up Asia-Pacific markets
to increased deliveries of Canadian crude oil.
producers unless the shipper itself happens to be a producer
and moving his own barrels.”
At stake is access to competitively-priced gas for customers
in much of Ontario and Quebec. Industrial and residential
end-users eager to take advantage of booming U.S. production and unwilling to be locked into long-term contracts for
gas delivered from western Canada. In a suit filed in Ontario
court, TransCanada claims that it concluded an agreement
early this year with Enbridge’s Toronto-based distribution
utility to proceed jointly with a short spur that would bring
more gas into the Greater Toronto Area from various sources.
TransCanada said Enbridge unilaterally terminated a memorandum of understanding last month and proceeded to offer
all the capacity on the proposed line to its own customers.
Claiming it would suffer “irreparable harm,” the Calgary-based
pipeline company has asked the court to force Enbridge to
abide by the terms of the MOU, or award it $4.5-billion
in damages.
Other firms that have entered into agreements for service on the
half-century-old pipeline system include U.S. Oil & Refining
Co., PetroChina International America Inc. and Astra Energy
Canada Inc. The five firms have together committed to ship
54,000 barrels per day following an open season conducted
last fall that drew a total of 95,000 barrels per day of support
for guaranteed access to the Westridge marine terminal.
Enbridge issued a statement Monday that claims the agreement was invalidated because TransCanada was not prepared
to make gas from the pipeline available to all customers in
the region, a contravention of provincial rules. “The actions
they took did not allow us to meet the standard of ensuring
open, non-discriminatory access” as required by the Ontario
Energy Board, said Guy Jarvis, President of Enbridge Gas
Distribution. In an interview, Mr. Jarvis said the Segment A
line is required to ensure the utility has sufficient high-pressure
pipeline capacity to supply enough gas to meet growing
needs in the Toronto region, and will also give it greater access
to growing American supplies. He said the legal dispute is
separate from the fight that Enbridge and other Ontario and
Quebec customers are having with TransCanada over its main
pipeline that brings western gas to central Canada.
Since 2003, space on the pipeline has been allocated between
uncommitted shippers and dock users using a “bid premium”
method. Kinder Morgan wants to fund future expansions on
the West Coast pipeline – to 700,000 barrels per day, up
from a capacity of 300,000 today – using firm service fees
paid by shippers. Although the issue drew criticism from
common carriage users of the line in hearings before the
NEB, there remains broad consensus that reaching Pacific
tidewater is in the industry’s best interests. Kinder Morgan’s
expansion plans are “the next or the very first step in the
West Coast piece that’s already played out in the U.S. Gulf
Coast,” offered Paul Reimer, Senior Vice-President of Marketing,
Transportation and Power at Cenovus. In testimony before
the board, he predicted expansion of the TMPL system would
precipitate increased exports to Asia-Pacific markets just as
the ExxonMobil Pegasus pipeline, foreshadowing Keystone’s
ultimate delivery capacity of 1.1 million barrels per day, successfully relieved congestion in the U.S. Midwest by delivering
100,000 barrels per day from Patoka, Illinois to refiners on
the Gulf Coast. Deanna Zumwalt, Nexen Inc.’s Vice-President,
North America, crude oil and marketing, said that getting
firm access to the Westridge dock, as opposed to nominating
monthly for it, “allows us to begin to build those relationships,
and prove up the concept that West Coast access makes
sense for producers.” Chevron Resources Canada trading
manager Geoff McCutcheon, whose firm uses the West Coast
pipeline to feed its refinery in Burnaby, noted in testimony to
the board that TMPL is primarily used by refined product
shippers and refineries in Washington State, whose traditional
feedstock from the Alaska North Slope is in terminal decline.
He said firm shippers would capture any available arbitrage, and questioned whether benefits would accrue in equal
measure to the industry as a whole as opposed to a handful of
individual players. “In the future that money will roll to the
firm shippers,” he told the board. “It will not flow back to the
Following a National Energy Board decision in March that
limited tariff increases on the mainline, TransCanada is trying
to force customers to sign 10- to 15-year contracts for service
in Ontario. While the mainline is under-utilized from Alberta
to Northern Ontario, service is in greater demand in the rest
of the province and in Quebec. The pipeline company also
plans to convert some capacity on the mainline from gas to
oil as part of its Energy East project to ship some 1.1-million
barrels per day of crude from Alberta to Quebec and New
Brunswick. TransCanada has said it will provide service to
gas customers willing to contract long-term, but warned that
costs could escalate.
“There is a change in the landscape taking place,” Mr. Jarvis
said, “And our role is to represent the interests of our 2-million
customers in our franchise area.” While TransCanada aims to
protect the value of its mainline system, Ontario distributors
and industrial users are keen to diversify their supply base
and take advantage of booming production south of the
border. But they need the new pipeline capacity to do so.
the other is a new fuel technology to reduce the carbondioxide emissions from oil sands produced from underground
steam-injection. “A technology that has the potential to
substantially reduce reclamation times would traditionally
be held very close by an individual company, while other
companies would work to develop something very similar,”
Devon Canada President Chris Seasons said at the signing.
“This slows down progress, is redundant, and ties up valuable
people and resources,” Seasons stated. The seeds of the new
group were started in 2010, when seven of the companies
agreed to share technology specifically related to the cleanup of tailings ponds - large pools of waste water created
from oil-sands mining. That group will be merged into the
new group, the companies said.
Twelve of the Canada’s largest oil-sands producers have
agreed to share funding for environmental research,
agreeing that pooling their resources will speed the creation
of new technologies to reduce the negative effects of oilsands development. The 12 companies involved in the new
organization, called Canada’s Oil Sands Innovation
Alliance, have agreed to jointly fund environmental research
and then share the intellectual property rights for environmental technologies. “We will remain competitors and will
continue to compete aggressively in the market with our
products, but when it comes to the environment, we know
we’ll all win when we start working more closely together,”
Suncor Energy Inc.’s (SU) Chief Operating Officer and
incoming chief executive, Steve Williams, said before
signing the charter of the new group at a press conference
in Calgary.
An Alberta government report has stated that stronger, more
detailed safety and environmental rules need to be in place
before carbon capture and storage (CCS) technology can be
brought into widespread use. The province is relying on the
technology to reduce its greenhouse gas emissions (GHG) as
Alberta continues to use its vast coal resources for power
generation. As Alberta’s industrial output sprawls, GHG emissions are projected to rise until at least 2020. The provincial
government has allocated $1.3-billion to two near term CCS
projects, and says 70 per cent of the GHG reductions that will
come in the longer term, by 2050, will be a result of broad
adoption of the technology. This CCS plan has been part of
the Alberta sales pitch Premier Alison Redford has made during
her various trade trips to the U.S. where approval of TransCanada
Corp.’s Keystone XL pipeline has been front and centre.
There is strong incentive for Alberta to try to polish its environmental credibility. U.S. President Barack Obama has vowed
that the cross-border Keystone XL pipeline will only get the
green light from his administration if it doesn’t add to global
greenhouse gas emissions. Environmentalists have argued
that approval of the pipeline project will spur production in
the carbon-intensive oil sands, and worsen climate change.
Responding to such criticisms, Alberta has decided to focus
much of its climate change policy and dollars on CCS tecnology, which sees carbon dioxide collected from a large indutrial
source and then injected into a deep underground geological
formation. “For a small population of four million people, Alberta
has committed a lot,” Alberta Energy Minister Ken Hughes said
in an interview. “It is one element in the suite of aproaches that
we are pursuing in order to demonstrate to the rest of the world
that we are a responsible developer of energy resources.”
Oilsands samples
Oil-sands development is being targeted by environmental
groups and politicians for the higher greenhouse gas emissions it creates, along with the perception of land destruction
and waste ponds created by strip mining in northern Alberta.
Resistance to the Keystone XL oil pipeline from Canada to
Texas was rejected by the U.S. government due in part to
what the environmental groups called “dirty” oil from Canada’s
oil sands. The oil sands in northeastern Alberta is the world’s
third-largest oil reserve and is expected to roughly double
in production to 3 million barrels a day by the end of
this decade.
The companies that signed onto the agreement include: BP
Plc, Canadian Natural Resources Ltd., Cenovus Energy Inc.,
ConocoPhillips, Devon Energy Corp., Imperial Oil Ltd.,
Nexen Inc., Royal Dutch Shell, Statoil, Suncor Energy, Teck
Resources Ltd. and Total SA.
According to the Alberta government’s CCS Regulatory
Framework Assessment report released recently, the province’s push to become a world CCS leader could mean more
pipelines crisscrossing Alberta, a possible shortage of sequestration sites, and an increase in amine solvents (used to
wash carbon dioxide out of a gas mixture) which are subsequently released into the environment. The report states
laws, regulations and public consultations need to be
tailored specifically to CCS projects, and for the time being,
The consortium is focusing on two technologies to improve
environmental performance. The initial technology will speed
up the land reclamation process after oil-sands strip mining,
environmental assessments of CCS projects should be
mandatory. Alberta had originally planned to have four
private sector carbon capture projects now under construction but two were cancelled when companies decided
that even with a government-infusion of dollars, the projects
no longer made economic sense. The two remaining
projects are Shell’s Quest project, that will capture emissions
from an oil sands upgrader, and Enhance Energy Inc.’s
trunk line, which will use emissions from an oil upgrader
and an Agrium plant for “enhanced oil recovery” – which the
report puts in a separate category from regular
CCS projects.
project to approximately $525 million. Flooding in Calgary
in June also delayed work as suppliers were not able to get
equipment to the site. The company says it will maintain staff
at the West Ells site to continue with reduced work activities
and to ensure safety of the worksite. “We are confident that
Sunshine’s extensive asset base and very advanced first
project at West Ells will enable us to obtain commitments
for necessary funding,” Sunshine President John Zahary said
in a statement. Sunshine has secured about one million acres
of oilsands leases in the area.
The government is now asking for public input on its steering
committee’s 71 recommendations. Stephen Kaufman, general
manager of sustainable development for oil sands at Suncor
Energy Inc., said the report, which looked at the current rules
for CCS in Alberta and best practices from around the world,
is comprehensive.“The industry thinks that CO2 capture and
storage is potentially a very important solution on greenhouse
gas emissions.”
Visions of the Exxon Valdez disaster, where the supertanker
ran aground in Alaska’s Prince William Sound in 1989 and
spilled 257,000 barrels of oil, have not died away. New plans to
move crude oil by these massive vessels inevitably raises concerns and opposition. That holds true for Vancouver, despite
the fact the city’s world-class port (No. 1 in terms of export
tonnage in North America) has been exporting liquid fuels to
California from refineries in Edmonton for about 60 years.
These petroleum products have been transported by the aging,
Trans Mountain pipeline to Kinder Morgan Canada’s Westridge
Marine terminal in Burnaby’s Burrard Inlet. The amount of
crude oil leaving Vancouver bound for offshore markets is set
to increase if Kinder Morgan Canada has its way. Its project
hasn’t received the attention or created the headlines that
another export scheme has Enbridge Inc.’s controversial
Northern Gateway pipeline, but the Canadian arm of Houstonbased Kinder Morgan wants to double the current pipeline
capacity of the Trans Mountain pipeline from 300,000 barrels
per day (bpd) per day to as much as 700,000 bpd. Almost all
of it will be pumped into tankers bound for offshore markets.
On August 29,2013, UC Santa Barbara released the results
of a study on the effects of Heavy-Metal pollutants on fish
near oil and gas production platforms. The findings have
been published in the prestigious Bulletin of Marine Science.
Doctor Milton S. Love, PhD. and his team of researchers from
the UCSB’s Marine Science Institute examined 196 fish; 18
kelp bass (Paralabrax clathratus), 80 kelp rockfish (Sebastes
atrovirens), and 98 Pacific sanddab (Citharichthys sordidus).
The samples were taken from five offshore oil platforms and
10 natural areas between the Santa Barbara Channel in the
north and Long Beach in the south. Twenty-seven active and
seven decommissioned offshore platforms are located within
the study area. The scientists analyzed whole-body fish
samples looking for elevated levels of heavy-metal pollutants.
Of the 63 elements the researchers were testing for, 42 were
excluded from statistical comparisons because they were
not detected during analysis, were detected at concentrations
too low to yield reliable quantitative measurements, or were
deemed unlikely to accumulate to potentially toxic
concentrations. In layman’s terms, none of the 63 elements
were found at levels that could be considered dangerous, or
in some cases, even detected. None of the remaining 21 elements consistently exhibited higher concentrations at oil
platforms than at natural areas. The study concluded with
the statement that “recent ecological studies indicate that
platforms provide artificial structure for marine life, including
many fish species of recreational and commercial importance,
and may contribute to rebuilding overfished stocks.” Long
and short of it; it’s now official: oil and gas platforms are
GOOD for fish!
Just as the proposal promises to assist industry in its battle
to free itself from persistent crude price discounts, and even
though it would make Vancouver a bigger, and more important,
crude oil gateway, so too will the proposal increase tanker
traffic and the risk of a catastrophic Exxon Valdez-like spill
in an area over two million people call home. And as Kinder
Morgan Canada embarked this fall on public consultations
for the proposed project, its quiet expansion plan is poised
to get noisy. “We’ve developed world-class best practices for
the transportation of oil, especially under the Second Narrows.”
“We had somewhere between 20 and 30 companies interested during the recent open season, and nine of the companies have committed to firm service,” says Kinder Morgan
Canada CEO Ian Anderson. “We are very fortunate to have
a very broad inclusion of producers.” Cenovus Energy Inc.,
Canadian Oil Sands, Nexen and Devon Canada have signed
on so far. In fact, Kinder Morgan Canada’s expansion (the
pipeline has been in operation since 1953) could be ready
before the Northern Gateway pipeline, which proposes to
ship 525,000 bpd of bitumen from Alberta to the northern
B.C. port of Kitimat. With a strong safety record and existing
right-of-way agreements already in place, twinning the Trans
Mountain pipeline would seem to have few hurdles in dealing
Heavy rain and flooding in the area have already put development of the site behind schedule and forced up costs of the
The government was sending a boat to the stretch of affected
river Tuesday to take a closer look. Crews were to examine
rocks and beaches along the river and also the location where
it flows into Lake Athabasca.
Energy companies in the area say they haven’t experienced
any spills or releases.
with aboriginal groups, public and private stakeholders.
Nevertheless, the project has encountered turbulence. The
city councils of Vancouver, Burnaby and West Vancouver are
all opposed to the expansion, citing concerns about the risk
of degradation to the city’s waterfront and the cost to taxpayers if there ever was a heavy oil spill.
The dispute comes amid an escalating battle between
TransCanada and local gas distributors in Ontario and Quebec
as they respond to a rapidly changing North American gas
market, in which new extraction technology has increased
U.S. production
A northern Alberta Native band says a mysterious oily sheen
on the Athabasca River appears to be spreading and is lapping
at the shores of Fort Chipewyan. “It’s not a huge amount,”
Eriel Deranger, spokeswoman for the Athabasca Chipewyan
First Nation, said. “But there is obviously a petrochemical of
some kind in the Athabasca River system in such great quantities from upstream that it is now residing on the shores of
Lake Athabasca.” Reports of dead fish are also coming in.
“There are numerous reports of dead fish being found along
the delta, within the lake and the river system,” Deranger said.
“None of the land users have ever heard of or seen anything
like this on the Athabasca.” The sheen was first spotted one
Friday night in September, said Deranger. “A member of the
(First Nations) was boating from Fort McMurray to Fort
Chipewyan and just before he reached Poplar Point reserve,
he started noticing that there was oil residue on the water,”
she said. “It wasn’t just a small area. The sheen was shoreline
to shoreline.”
Oily sheen on river
Potter said one possible explanation is that heavy rains recently caused an unusual amount of erosion along the banks
of the river, which cuts through natural bitumen deposits.
High temperatures that followed may have softened the
freshly exposed bitumen and allowed more than the usual
amount to seep into the waterway. Deranger said chemical
analysis should be able to tell fairly readily whether the
substance is natural bitumen or a refined petrochemical.
Crews from the First Nation responded Saturday morning.
The provincial government and Alberta’s energy regulator
were also notified. As a precaution, the community’s water
intake on Lake Athabasca was shut down. It is still closed.
Athabasca Chipewyan Chief Allan Adam and others from the
band went up in a helicopter to survey the river. “He and the
folks on the ground realized that the sheen was much larger
than five kilometres,” Deranger said. “It wasn’t shore to shore
in all places but the sheen extended more than 100 kilometres.”
Teams from Alberta Environment also took to the skies on
Saturday and couldn’t see anything, said spokeswoman
Jessica Potter. “It landed a couple of times where they saw
some darkening, but it was determined to be silt. They couldn’t
see a sheen.” A sheen was clearly visible in photographs taken
by band members Saturday. Water samples taken by both
the government and band are being analyzed. Band officials
were also collecting samples and photographs of dead fish.
Either way, she said, the people of Fort Chipewyan have
health concerns. “Even if this is natural, it poses a serious
health risk. The fact that the government has completely
failed to do anything to remediate or clean up this film shows
their lack of concern.” Potter said new, more intensive environmental monitoring on the Athabasca should eventually
help in such situations.
“These are the things we’re looking to differentiate, what’s
the background and what’s new. That is the goal of the joint
oilsands monitoring program, to really get an actual understanding of the full scope of what’s going on, rather than just
compliance monitoring.”